Determining a hydraulic fracture completion configuration for a wellbore

ABSTRACT

Embodiments of determining a hydraulic fracture completion configuration for a wellbore that extends through a subterranean formation are provided herein. Embodiments of performing a hydraulic fracturing operation on a wellbore that extends through a subterranean formation are also provided herein.

CROSS REFERENCES TO RELATED APPLICATIONS

This application claims the benefit of priority to U.S. ProvisionalApplication No. 62/930,055, filed Nov. 4, 2019, which is incorporated byreference herein in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

TECHNICAL FIELD

The present disclosure relates to hydraulic fracture completions.

BACKGROUND

The hydrocarbon industry recovers hydrocarbons that are trapped insubsurface reservoirs (also known as subsurface formations). Thehydrocarbons can be recovered by drilling wellbores (also known aswells) into the reservoirs and the hydrocarbons are able to flow fromthe reservoirs into the wellbores and up to the surface. FIG. 1Aillustrates one example with heterogenous or poor fluid distribution ineach cluster creating non-equal fracture geometry. Moreover, multiplestudies have shown that heel-ward bias of proppant and fluid occurs.Inefficient fracture placement results in understimulated reservoir,poor production and recovery, fracture hit and interference, andinefficient reservoir management. Efforts to overcome these challengeshave been largely trial and error. Thus, there exists a need in the areahydraulic fracture completions.

SUMMARY

Embodiments of determining a hydraulic fracture completion configurationfor a wellbore that extends through a subterranean formation areprovided herein.

One embodiment of a computer-implemented method of determining ahydraulic fracture completion configuration for a wellbore that extendsthrough a subterranean formation comprising: calculating a stressprofile across a plurality of perforation clusters within a fracturestage of the wellbore; and calculating a fracture pressure parameter foreach perforation cluster of the plurality of perforation clusters withinthe fracture stage of the wellbore as a function of the stress profileacross the plurality of perforation clusters within the fracture stage,a perforation friction that accounts for perforation hole erosion, afracture net pressure, and a fracture closure pressure. The embodimentfurther comprises determining a quantity of perforation clusters in theplurality of the perforation clusters within the fracture stage, aquantity of perforation holes for each perforation cluster of theplurality of perforation clusters within the fracture stage, a diameterof the perforation holes for each perforation cluster of the pluralityof perforation clusters within the fracture stage, a spacing betweeneach perforation cluster of the plurality of perforation clusters withinthe fracture stage, an injection distribution across the plurality ofperforation clusters within the fracture stage, or any combinationthereof, for the hydraulic fracture completion configuration based onthe calculated fracture pressure parameters.

One embodiment of a computer system comprises one or more processors;memory; and one or more programs. The one or more programs are stored inthe memory and configured to be executed by the one or more processors.The one or more programs include instructions that when executed by theone or more processors cause execution of a method of determining ahydraulic fracture completion configuration for a wellbore that extendsthrough a subterranean formation. The method comprises: calculating astress profile across a plurality of perforation clusters within afracture stage of the wellbore; and calculating a fracture pressureparameter for each perforation cluster of the plurality of perforationclusters within the fracture stage of the wellbore as a function of thestress profile across the plurality of perforation clusters within thefracture stage, a perforation friction that accounts for perforationhole erosion, a fracture net pressure, and a fracture closure pressure.The embodiment further comprises determining a quantity of perforationclusters in the plurality of the perforation clusters within thefracture stage, a quantity of perforation holes for each perforationcluster of the plurality of perforation clusters within the fracturestage, a diameter of the perforation holes for each perforation clusterof the plurality of perforation clusters within the fracture stage, aspacing between each perforation cluster of the plurality of perforationclusters within the fracture stage, an injection distribution across theplurality of perforation clusters within the fracture stage, or anycombination thereof, for the hydraulic fracture completion configurationbased on the calculated fracture pressure parameters.

One embodiment of a method of performing a hydraulic fracturingoperation on a wellbore that extends through a subterranean formationcomprises performing a hydraulic fracturing operation on the wellboreusing a hydraulic fracture completion configuration. In the embodiment,the hydraulic fracture completion configuration is determined by:calculating a stress profile across a plurality of perforation clusterswithin a fracture stage of the wellbore; and calculating a fracturepressure parameter for each perforation cluster of the plurality ofperforation clusters within the fracture stage of the wellbore as afunction of the stress profile across the plurality of perforationclusters within the fracture stage, a perforation friction that accountsfor perforation hole erosion, a fracture net pressure, and a fractureclosure pressure. The embodiment further comprises determining aquantity of perforation clusters in the plurality of the perforationclusters within the fracture stage, a quantity of perforation holes foreach perforation cluster of the plurality of perforation clusters withinthe fracture stage, a diameter of the perforation holes for eachperforation cluster of the plurality of perforation clusters within thefracture stage, a spacing between each perforation cluster of theplurality of perforation clusters within the fracture stage, aninjection distribution across the plurality of perforation clusterswithin the fracture stage, or any combination thereof, for the hydraulicfracture completion configuration based on the calculated fracturepressure parameters.

One embodiment of a system of performing a hydraulic fracturingoperation on a wellbore that extends through a subterranean formationcomprises: a perforation gun for generating perforations in the wellboreaccording to a hydraulic fracture completion configuration. Thehydraulic fracture completion configuration is determined by calculatinga stress profile across a plurality of perforation clusters within afracture stage of the wellbore; and calculating a fracture pressureparameter for each perforation cluster of the plurality of perforationclusters within the fracture stage of the wellbore as a function of thestress profile across the plurality of perforation clusters within thefracture stage, a perforation friction that accounts for perforationhole erosion, a fracture net pressure, and a fracture closure pressure.The embodiment further comprises determining a quantity of perforationclusters in the plurality of the perforation clusters within thefracture stage, a quantity of perforation holes for each perforationcluster of the plurality of perforation clusters within the fracturestage, a diameter of the perforation holes for each perforation clusterof the plurality of perforation clusters within the fracture stage, aspacing between each perforation cluster of the plurality of perforationclusters within the fracture stage, an injection distribution across theplurality of perforation clusters within the fracture stage, or anycombination thereof, for the hydraulic fracture completion configurationbased on the calculated fracture pressure parameters. The embodimentfurther comprises a pump and an injection line configured to injectfluid through the generated perforations of the wellbore into thesubterranean formation to perform the hydraulic fracturing operation.

DESCRIPTION OF THE DRAWINGS

FIG. 1A illustrates one example with heterogenous or poor fluiddistribution in each cluster creating non-equal fracture geometry.

FIG. 1B illustrates one example with an aim to create equal fracturegeometry with equal fluid distribution in each cluster.

FIG. 2 illustrates one embodiment of a system for executing one or morecomputer implemented methods discussed herein.

FIG. 3 illustrates one embodiment of a method of determining a hydraulicfracture completion configuration for a wellbore that extends through asubterranean formation.

FIGS. 4A-4G illustrate various flowcharts of various embodiments ofmethods consistent with the principles of the present disclosure.

FIG. 5 illustrates one embodiment of stress shadow in context.

FIG. 6 illustrates proppant concentration profiles for a heel clusterand a toe cluster.

FIG. 7 is a diagram illustrating one embodiment of deviation % forindividual designs.

FIGS. 8-12 illustrate various slurry rate distribution examples.

FIG. 13 illustrates one embodiment of sensitivity analysis output.

FIG. 14 illustrates another embodiment of sensitivity analysis output.

FIGS. 15A, 15B, 15C, and 15D illustrates various examples of a layout.

FIGS. 16-28 illustrate various screenshots and output that may begenerated consistent with the instant disclosure.

FIG. 29 is a flowchart of one embodiment of determining proppantdistribution for a plurality of clusters within a fracture stage of awellbore.

FIG. 30 illustrates one embodiment of a horizontal wellbore withmultiple stages.

FIG. 31A illustrates a setup for conventional CFD modeling.

FIG. 31B illustrates a setup for the CFD modeling consistent with thedisclosure.

FIG. 32 illustrates a setup for the CFD modeling consistent with thedisclosure.

FIG. 33 illustrates that a 100-ft pipe segment ahead of each stage issufficient

FIG. 34 illustrates fluid streamline (grey color) and proppantstreamline (black color) exiting through the perforation, as well asproppant concentration profile (equilibrium state) along a cross-sectionof the wellbore.

FIG. 35 illustrates SES of both proppant and fluid do not change withperforation azimuth, if the other parameters are the same.

FIG. 36 illustrates one embodiment of an equilibrium proppantconcentration profile for the portion of the wellbore without anyopenings, as well as one embodiment of an equilibrium velocity profilefor the portion of the wellbore without any openings.

FIG. 37 illustrates examples validating proppant efficiency determinedfor at least one other opening of the wellbore at a different azimuth.

FIG. 38 illustrates one embodiment of response time of a machinelearning model.

FIG. 39 illustrates example results of a trained model.

FIG. 40 illustrates a flowchart of one embodiment of a method of using amodel to determine the proppant distribution for the plurality ofclusters within the fracture stage of the wellbore without a multiplier.

FIG. 41 illustrates a graph with three examples (Cluster Total, BottomPerforation, and Top Perforation) showing proppant distributions.

FIG. 42 illustrates a setup for determining a multiplier.

FIG. 43 illustrates the difference in proppant concentration fromequilibrium state in one example.

FIG. 44 illustrates a flowchart of one embodiment of a method of using amodel to determine the proppant distribution for the plurality ofclusters within the fracture stage of the wellbore with a multiplier.

FIG. 45 illustrates the distribution of proppant concentration acrossthe cross-section of a wellbore at different perforation clusters alongthe wellbore

FIG. 46 illustrates an examples of no plugging (left) and plugging(right).

FIG. 47A illustrates one embodiment of a wellbore to fractureconnectivity apparatus.

FIG. 47B illustrates various embodiments of the opening portion of thewellbore to fracture connectivity apparatus of FIG. 47A.

FIG. 47C illustrates various embodiments of the opening portion of thewellbore to fracture connectivity apparatus of FIG. 47A.

FIG. 47D illustrates another embodiment of the wellbore to fractureconnectivity apparatus.

FIG. 47E illustrates another embodiment of the wellbore to fractureconnectivity apparatus.

FIG. 47F illustrates another embodiment of the wellbore to fractureconnectivity apparatus.

FIG. 47G illustrates one embodiment of the fracture portion of thewellbore to fracture connectivity apparatus of FIG. 47A.

FIG. 47H illustrates various embodiments of the fracture portion of thewellbore to fracture connectivity apparatus of FIG. 47A.

FIG. 47I illustrates various embodiments of the fracture portion of thewellbore to fracture connectivity apparatus of FIG. 47A.

FIG. 47J illustrates various embodiments of the fracture portion of thewellbore to fracture connectivity apparatus of FIG. 47A.

FIG. 47K illustrates one embodiment of a plurality of the wellbore tofracture connectivity apparatus of FIG. 47A that are coupled together.

FIG. 47L illustrates another embodiment of a plurality of the wellboreto fracture connectivity apparatus of FIG. 47A that are coupledtogether.

FIG. 47M illustrates one embodiment of a system that includes at leastone of the wellbore to fracture connectivity apparatus of FIG. 47Acoupled to a wellbore portion.

FIG. 47N illustrates a more detailed view of the system of FIG. 47M.

FIG. 48 is a flowchart of one embodiment of a method of using thewellbore to fracture connectivity apparatus of FIG. 47A.

Reference will now be made in detail to various embodiments, where likereference numerals designate corresponding parts throughout the severalviews. In the following detailed description, numerous specific detailsare set forth in order to provide a thorough understanding of thepresent disclosure and the embodiments described herein. However,embodiments described herein may be practiced without these specificdetails. In other instances, well-known methods, procedures, components,and mechanical apparatuses have not been described in detail so as notto unnecessarily obscure aspects of the embodiments.

DETAILED DESCRIPTION

Terminology: The following terms will be used throughout thespecification and will have the following meanings unless otherwiseindicated.

Formation: Hydrocarbon exploration processes, hydrocarbon recovery (alsoreferred to as hydrocarbon production) processes, or any combinationthereof may be performed on a formation. The formation refers topractically any volume under a surface. For example, the formation maybe practically any volume under a terrestrial surface (e.g., a landsurface), practically any volume under a seafloor, etc. A water columnmay be above the formation, such as in marine hydrocarbon exploration,in marine hydrocarbon recovery, etc. The formation may be onshore. Theformation may be offshore (e.g., with shallow water or deep water abovethe formation). The formation may include faults, fractures,overburdens, underburdens, salts, salt welds, rocks, sands, sediments,pore space, etc. Indeed, the formation may include practically anygeologic point(s) or volume(s) of interest (such as a survey area) insome embodiments.

The formation may include hydrocarbons, such as liquid hydrocarbons(also known as oil or petroleum), gas hydrocarbons (e.g., natural gas),solid hydrocarbons (e.g., asphaltenes or waxes), a combination ofhydrocarbons (e.g., a combination of liquid hydrocarbons and gashydrocarbons) (e.g., a combination of liquid hydrocarbons, gashydrocarbons, and solid hydrocarbons), etc. Light crude oil, medium oil,heavy crude oil, and extra heavy oil, as defined by the AmericanPetroleum Institute (API) gravity, are examples of hydrocarbons.Examples of hydrocarbons are many, and hydrocarbons may include oil,natural gas, kerogen, bitumen, clathrates (also referred to ashydrates), etc. The hydrocarbons may be discovered by hydrocarbonexploration processes.

The formation may also include at least one wellbore. For example, atleast one wellbore may be drilled into the formation in order to confirmthe presence of the hydrocarbons. As another example, at least onewellbore may be drilled into the formation in order to recover (alsoreferred to as produce) the hydrocarbons. The hydrocarbons may berecovered from the entire formation or from a portion of the formation.For example, the formation may be divided into one or more hydrocarbonzones, and hydrocarbons may be recovered from each desired hydrocarbonzone. One or more of the hydrocarbon zones may even be shut-in toincrease hydrocarbon recovery from a hydrocarbon zone that is notshut-in.

The formation, the hydrocarbons, or any combination thereof may alsoinclude non-hydrocarbon items. For example, the non-hydrocarbon itemsmay include connate water, brine, tracers, items used in enhanced oilrecovery or other hydrocarbon recovery processes, etc.

In short, each formation may have a variety of characteristics, such aspetrophysical rock properties, reservoir fluid properties, reservoirconditions, hydrocarbon properties, or any combination thereof. Forexample, each formation (or even zone or portion of the formation) maybe associated with one or more of: temperature, porosity, salinity,permeability, water composition, mineralogy, hydrocarbon type,hydrocarbon quantity, reservoir location, pressure, etc. Indeed, thoseof ordinary skill in the art will appreciate that the characteristicsare many, including, but not limited to: shale gas, shale oil, tightgas, tight oil, tight carbonate, carbonate, vuggy carbonate,unconventional (e.g., a rock matrix with an average pore size less than1 micrometer), diatomite, geothermal, mineral, metal, a formation havinga permeability in the range of from 0.000001 millidarcy to 25 millidarcy(such as an unconventional formation), a formation having a permeabilityin the range of from 26 millidarcy to 40,000 millidarcy, etc.

The terms “formation”, “subsurface formation”, “hydrocarbon-bearingformation”, “reservoir”, “subsurface reservoir”, “subsurface region ofinterest”, “subterranean reservoir”, “subsurface volume of interest”,“subterranean formation”, and the like may be used synonymously. Theterms “formation”, “hydrocarbons”, and the like are not limited to anydescription or configuration described herein.

Wellbore: A wellbore refers to a single hole, usually cylindrical, thatis drilled into the formation for hydrocarbon exploration, hydrocarbonrecovery, surveillance, or any combination thereof. The wellbore isusually surrounded by the formation and the wellbore may be configuredto be in fluidic communication with the formation (e.g., viaperforations in the wellbore generated with a perforation gun). Thewellbore may also be configured to be in fluidic communication with thesurface, such as in fluidic communication with a surface facility thatmay include oil/gas/water separators, gas compressors, storage tanks,pumps, gauges, sensors, meters, pipelines, etc.

The wellbore may be used for injection (sometimes referred to as aninjection wellbore) in some embodiments. The wellbore may be used forproduction (sometimes referred to as a production wellbore) in someembodiments. The wellbore may be used for a single function, such asonly injection, in some embodiments. The wellbore may be used for aplurality of functions, such as injection and then production, in someembodiments. For example, a single wellbore may be utilized forinjection and hydrocarbon production, such as a single wellbore used forhydraulic fracturing and hydrocarbon production. A plurality ofwellbores (e.g., tens to hundreds of wellbores) are often used in afield to recover hydrocarbons.

The wellbore may have straight, directional, or a combination oftrajectories. For example, the wellbore may be a vertical wellbore, ahorizontal wellbore, a multilateral wellbore, an inclined wellbore, aslanted wellbore, etc. The wellbore may include a change in deviation.As an example, the deviation is changing when the wellbore is curving.In a horizontal wellbore, the deviation is changing at the curvedsection (sometimes referred to as the heel). As used herein, ahorizontal section of a wellbore is drilled in a horizontal direction(or substantially horizontal direction). For example, a horizontalsection of a wellbore is drilled towards the bedding plane direction. Ahorizontal section of a wellbore may be, but is not limited to, ahorizontal section of a horizontal wellbore. On the other hand, avertical wellbore is drilled in a vertical direction (or substantiallyvertical direction). For example, a vertical wellbore is drilledperpendicular (or substantially perpendicular) to the bedding planedirection. The wellbore may be drilled amongst existing wellbores, forexample, as an infill wellbore.

The wellbore may include a plurality of components, such as, but notlimited to, a casing, a liner, a sleeve, a tubing string, a heatingelement, a sensor, a packer, a screen, a gravel pack, artificial liftequipment (e.g., an electric submersible pump (ESP)), etc. The “casing”refers to a steel pipe cemented in place during the wellboreconstruction process to stabilize the wellbore. The “liner” refers toany string of casing in which the top does not extend to the surface butinstead is suspended from inside the previous casing. The “tubingstring” or simply “tubing” is made up of a plurality of tubulars (e.g.,tubing, tubing joints, pup joints, etc.) connected together. The tubingstring is lowered into the casing or the liner for injecting a fluidinto the formation, producing a fluid from the formation, or anycombination thereof. The casing may be cemented in place, with thecement positioned in the annulus between the formation and the outsideof the casing. The wellbore may also include any completion hardwarethat is not discussed separately. If the wellbore is drilled offshore,the wellbore may include some of the previous components plus otheroffshore components, such as a riser.

The wellbore may also include equipment to control fluid flow into thewellbore, control fluid flow out of the wellbore, or any combinationthereof. For example, each wellbore may include a wellhead, a BOP,chokes, valves, or other control devices. These control devices may belocated on the surface, under the surface (e.g., downhole in thewellbore), or any combination thereof. In some embodiments, the samecontrol devices may be used to control fluid flow into and out of thewellbore. In some embodiments, different control devices may be used tocontrol fluid flow into and out of the wellbore. In some embodiments,the rate of flow of fluids through the wellbore may depend on the fluidhandling capacities of the surface facility that is in fluidiccommunication with the wellbore. The control devices may also beutilized to control the pressure profile of the wellbore.

The equipment to be used in controlling fluid flow into and out of thewellbore may be dependent on the wellbore, the formation, the surfacefacility, etc. However, for simplicity, the term “control apparatus” ismeant to represent any wellhead(s), BOP(s), choke(s), valve(s),fluid(s), and other equipment and techniques related to controllingfluid flow into and out of the wellbore.

The wellbore may be drilled into the formation using practically anydrilling technique and equipment known in the art, such as geosteering,directional drilling, etc. Drilling the wellbore may include using atool, such as a drilling tool that includes a drill bit and a drillstring. Drilling fluid, such as drilling mud, may be used while drillingin order to cool the drill tool and remove cuttings. Other tools mayalso be used while drilling or after drilling, such asmeasurement-while-drilling (MWD) tools, seismic-while-drilling (SWD)tools, wireline tools, logging-while-drilling (LWD) tools, or otherdownhole tools. After drilling to a predetermined depth, the drillstring and the drill bit are removed, and then the casing, the tubing,etc. may be installed according to the design of the wellbore.

The equipment to be used in drilling the wellbore may be dependent onthe design of the wellbore, the formation, the hydrocarbons, etc.However, for simplicity, the term “drilling apparatus” is meant torepresent any drill bit(s), drill string(s), drilling fluid(s), andother equipment and techniques related to drilling the wellbore.

The term “wellbore” may be used synonymously with the terms “borehole,”“well,” or “well bore.” The term “wellbore” is not limited to anydescription or configuration described herein.

Hydrocarbon recovery: The hydrocarbons may be recovered from theformation using a fracturing process. For example, a fracturing processmay include fracturing using electrodes, fracturing using fluid(oftentimes referred to as hydraulic fracturing), etc. The hydrocarbonsmay be recovered from the formation using radio frequency (RF) heating.Another hydrocarbon recovery process(s) may also be utilized to recoverthe hydrocarbons. Furthermore, those of ordinary skill in the art willappreciate that one hydrocarbon recovery process may also be used incombination with at least one other recovery process or subsequent to atleast one other recovery process. This is not an exhaustive list ofhydrocarbon recovery processes.

A hydraulic fracturing process may entail preparing an injection fluid(oftentimes referred to a fracturing fluid) and injecting thatfracturing fluid into the wellbore at a sufficient rate and pressure toopen existing fractures, create fractures, or any combination thereof inthe formation. The formation proximate to the wellbore may be fracturedfor the first time or refractured. The wellbore may be new or existing.The fractures permit hydrocarbons to flow more freely from the formationinto the wellbore. Fracturing may be performed onshore, offshore, or anycombination thereof.

In the hydraulic fracturing process, the fracturing fluid may beprepared on-site to include at least proppants. The proppants, such assand or other particles, are meant to hold the fractures open so thathydrocarbons can more easily flow to the wellbore. The fracturing fluidand the proppants may be blended together using at least one blender.The fracturing fluid may also include other components in addition tothe proppants. The wellbore and formation proximate to the wellbore arein fluid communication (e.g., via perforations in the wellbore generatedwith a perforation gun), and the fracturing fluid with the proppants isinjected into the wellbore through the wellhead of the wellbore using atleast one pump (oftentimes called a fracturing pump). The fracturingfluid with the proppants is injected at a sufficient rate and pressureto open existing fractures and/or create fractures in the formation. Asfractures become sufficiently wide to allow proppants to flow into thosefractures, proppants in the fracturing fluid are deposited in thosefractures during injection of the fracturing fluid. The fracturing fluidis removed by flowing or pumping it back out of the same wellbore sothat the fracturing fluid does not block the flow of hydrocarbons to thesame wellbore. The hydrocarbons will typically enter the same wellborefrom the formation and flow up to the surface for further processing.The fracturing process may involve clusters and staging in someembodiments.

The equipment to be used in preparing the fracturing fluid, injectingthe fracturing fluid, and fracturing with the fracturing fluid may bedependent on the fracturing fluid, on the proppants, on the wellbore,the formation, etc. However, for simplicity, the term “fracturingapparatus” is meant to represent any tank(s), mixer(s), blender(s),pump(s), manifold(s), line(s), valve(s), fluid(s), fracturing fluidcomponent(s), proppants, and other equipment and techniques related topreparing the fracturing fluid, injecting the fracturing fluid, andfracturing with the fracturing fluid. Those of ordinary will alsoappreciate that there may be some overlap between the “fracturingapparatus” and the equipment used in other hydrocarbon recoveryprocesses, such that some items (e.g., a tank, a mixer, etc.) may beused in multiple processes.

Other definitions: The term “proximate” is defined as “near”. If item Ais proximate to item B, then item A is near item B. For example, in someembodiments, item A may be in contact with item B. For example, in someembodiments, there may be at least one barrier between item A and item Bsuch that item A and item B are near each other, but not in contact witheach other. The barrier may be a fluid barrier, a non-fluid barrier(e.g., a structural barrier), or any combination thereof. Both scenariosare contemplated within the meaning of the term “proximate.”

The terms “comprise” (as well as forms, derivatives, or variationsthereof, such as “comprising” and “comprises”) and “include” (as well asforms, derivatives, or variations thereof, such as “including” and“includes”) are inclusive (i.e., open-ended) and do not excludeadditional elements or steps. For example, the terms “comprises” and/or“comprising,” when used in this specification, specify the presence ofstated features, integers, steps, operations, elements, and/orcomponents, but do not preclude the presence or addition of one or moreother features, integers, steps, operations, elements, components,and/or groups thereof. Accordingly, these terms are intended to not onlycover the recited element(s) or step(s), but may also include otherelements or steps not expressly recited. Furthermore, as used herein,the use of the terms “a” or “an” when used in conjunction with anelement may mean “one,” but it is also consistent with the meaning of“one or more,” “at least one,” and “one or more than one.” Therefore, anelement preceded by “a” or “an” does not, without more constraints,preclude the existence of additional identical elements.

The use of the term “about” applies to all numeric values, whether ornot explicitly indicated. This term generally refers to a range ofnumbers that one of ordinary skill in the art would consider as areasonable amount of deviation to the recited numeric values (i.e.,having the equivalent function or result). For example, this term can beconstrued as including a deviation of 10 percent of the given numericvalue provided such a deviation does not alter the end function orresult of the value. Therefore, a value of about 1% can be construed tobe a range from 0.9% to 1.1%. Furthermore, a range may be construed toinclude the start and the end of the range. For example, a range of 10%to 20% (i.e., range of 10%-20%) includes 10% and also includes 20%, andincludes percentages in between 10% and 20%, unless explicitly statedotherwise herein. Similarly, a range of between 10% and 20% (i.e., rangebetween 10%-20%) includes 10% and also includes 20%, and includespercentages in between 10% and 20%, unless explicitly stated otherwiseherein.

The term “if” may be construed to mean “when” or “upon” or “in responseto determining” or “in accordance with a determination” or “in responseto detecting,” that a stated condition precedent is true, depending onthe context. Similarly, the phrase “if it is determined [that a statedcondition precedent is true]” or “if [a stated condition precedent istrue]” or “when [a stated condition precedent is true]” may be construedto mean “upon determining” or “in response to determining” or “inaccordance with a determination” or “upon detecting” or “in response todetecting” that the stated condition precedent is true, depending on thecontext.

It is understood that when combinations, subsets, groups, etc. ofelements are disclosed (e.g., combinations of components in acomposition, or combinations of steps in a method), that while specificreference of each of the various individual and collective combinationsand permutations of these elements may not be explicitly disclosed, eachis specifically contemplated and described herein. By way of example, ifan item is described herein as including a component of type A, acomponent of type B, a component of type C, or any combination thereof,it is understood that this phrase describes all of the variousindividual and collective combinations and permutations of thesecomponents. For example, in some embodiments, the item described by thisphrase could include only a component of type A. In some embodiments,the item described by this phrase could include only a component of typeB. In some embodiments, the item described by this phrase could includeonly a component of type C. In some embodiments, the item described bythis phrase could include a component of type A and a component of typeB. In some embodiments, the item described by this phrase could includea component of type A and a component of type C. In some embodiments,the item described by this phrase could include a component of type Band a component of type C. In some embodiments, the item described bythis phrase could include a component of type A, a component of type B,and a component of type C. In some embodiments, the item described bythis phrase could include two or more components of type A (e.g., A1 andA2). In some embodiments, the item described by this phrase couldinclude two or more components of type B (e.g., B1 and B2). In someembodiments, the item described by this phrase could include two or morecomponents of type C (e.g., C1 and C2). In some embodiments, the itemdescribed by this phrase could include two or more of a first component(e.g., two or more components of type A (A1 and A2)), optionally one ormore of a second component (e.g., optionally one or more components oftype B), and optionally one or more of a third component (e.g.,optionally one or more components of type C). In some embodiments, theitem described by this phrase could include two or more of a firstcomponent (e.g., two or more components of type B (B1 and B2)),optionally one or more of a second component (e.g., optionally one ormore components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type C). In someembodiments, the item described by this phrase could include two or moreof a first component (e.g., two or more components of type C (C1 andC2)), optionally one or more of a second component (e.g., optionally oneor more components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type B).

This written description uses examples to disclose the invention,including the best mode, and also to enable any person skilled in theart to make and use the invention. The patentable scope is defined bythe claims, and may include other examples that occur to those skilledin the art. Such other examples are intended to be within the scope ofthe claims if they have elements that do not differ from the literallanguage of the claims, or if they include equivalent elements withinsubstantial differences from the literal language of the claims.

Unless defined otherwise, all technical and scientific terms used hereinhave the same meanings as commonly understood by one of skill in the artto which the disclosed invention belongs. All citations referred hereinare expressly incorporated by reference.

OVERVIEW: In unconventional resources horizontal wellbores, 5-15perforation clusters are fractured together in each stage of plug-n-perf(PnP) completion. Multiple studies have shown that heel-ward bias ofproppant and fluid occurs, and less than 60% of clusters are effectivelytreated. Inefficient fracture placement results in understimulatedreservoir, poor production and recovery, fracture hit and interference,and inefficient reservoir management. Efforts to overcome thesechallenges has been largely trial and error.

On the other hand, embodiments consistent with this disclosure mayinclude calculating a stress profile across a plurality of perforationclusters within a fracture stage of the wellbore; and calculating afracture pressure parameter for each perforation cluster of theplurality of perforation clusters within the fracture stage of thewellbore as a function of the stress profile across the plurality ofperforation clusters within the fracture stage, a perforation frictionthat accounts for perforation hole erosion, a fracture net pressure, anda fracture closure pressure. The embodiment further comprisesdetermining a quantity of perforation clusters in the plurality of theperforation clusters within the fracture stage, a quantity ofperforation holes for each perforation cluster of the plurality ofperforation clusters within the fracture stage, a diameter of theperforation holes for each perforation cluster of the plurality ofperforation clusters within the fracture stage, a spacing between eachperforation cluster of the plurality of perforation clusters within thefracture stage, an injection distribution across the plurality ofperforation clusters within the fracture stage, or any combinationthereof, for the hydraulic fracture completion configuration based onthe calculated fracture pressure parameters.

Advantageously, embodiments consistent with this disclosure may improvefracture placement efficiency. FIG. 1B illustrates one example with anaim to create equal fracture geometry with equal fluid distribution ineach cluster. For example, a more optimum perforation cluster design maybe obtained at reduced cost with ability to successfully pump up to 15cluster per stage with increased fracture placement efficiency. Forexample, fracture placement efficiency can be improved with optimumfracture entry design via embodiments consistent with this disclosureusing: VSC: Uses variable perforation friction to overcome stress shadowand heel-ward bias, Limited entry perforation: Uses perforation frictionto divert fluid to other clusters, Equal perforation hole diameter usingadvanced perforation charge designs to achieve equal and consistentperforation hole diameter.

Advantageously, embodiments consistent with this disclosure may use aperforation gun for generating perforations in the wellbore according toa hydraulic fracture completion configuration. For example, aperforation gun may be utilized to generate, in the wellbore, thedetermined quantity of perforation clusters in the plurality of theperforation clusters within the fracture stage. For example, aperforation gun or other device(s) may be utilized to generate, in thewellbore, the determined quantity of perforation holes for eachperforation cluster of the plurality of perforation clusters within thefracture stage. For example, a perforation gun may be utilized togenerate, in the wellbore, the determined diameter of the perforationholes for each perforation cluster of the plurality of perforationclusters within the fracture stage, and so on. Furthermore, a pump andan injection line configured to inject fluid through the generatedperforations of the wellbore into the subterranean formation may beutilized to perform the hydraulic fracturing operation. Advantageously,embodiments consistent with this disclosure may perform a hydraulicfracturing operation on the wellbore using a hydraulic fracturecompletion configuration.

System—FIG. 2 is a block diagram illustrating a system of determining ahydraulic fracture completion configuration for a wellbore that extendsthrough a subterranean formation, such as a system 200, in accordancewith some embodiments. While certain specific features are illustrated,those skilled in the art will appreciate from the present disclosurethat various other features have not been illustrated for the sake ofbrevity and so as not to obscure more pertinent aspects of theembodiments disclosed herein.

To that end, the system 200 includes one or more processing units (CPUs)202, one or more network interfaces 208 and/or other communicationinterfaces 203, memory 206, and one or more communication buses 204 forinterconnecting these and various other components. The system 200 alsoincludes a user interface 205 (e.g., a display 205-1 and an input device205-2). The communication buses 204 may include circuitry (sometimescalled a chipset) that interconnects and controls communications betweensystem components. An operator can actively input information and reviewoperations of system 200 using the user interface 205. User interface205 can be anything by which a person can interact with system 200,which can include, but is not limited to, the input device 205-2 (e.g.,a keyboard, mouse, etc.) or the display 205-1.

Memory 206 includes high-speed random access memory, such as DRAM, SRAM,DDR RAM or other random access solid state memory devices; and mayinclude non-volatile memory, such as one or more magnetic disk storagedevices, optical disk storage devices, flash memory devices, or othernon-volatile solid state storage devices. Memory 206 may optionallyinclude one or more storage devices remotely located from the CPUs 202.Memory 206, including the non-volatile and volatile memory deviceswithin memory 206, comprises a non-transitory computer readable storagemedium and may store data (e.g., input discussed further hereinbelow,output discussed further hereinbelow, etc.), models, images, etc. Inparticular embodiments, the computer readable storage medium comprisesat least some tangible devices, and in specific embodiments suchcomputer readable storage medium includes exclusively non-transitorymedia.

In some embodiments, memory 206 or the non-transitory computer readablestorage medium of memory 206 stores the following programs, modules anddata structures, or a subset thereof including an operating system 216,a network communication module 218, and a hydraulic fracture completionconfiguration determination module 220.

The operating system 216 includes procedures for handling various basicsystem services and for performing hardware dependent tasks.

The network communication module 218 facilitates communication withother devices via the communication network interfaces 208 (wired orwireless) and one or more communication networks, such as the Internet,other wide area networks, local area networks, metropolitan areanetworks, and so on.

In some embodiments, the system 200 may include four modules thatexecute the operations of the methods shown in the figures. An Optimizermodule 220 (e.g., A VSC Optimizer module), a Well Level Optimizationmodule 229, a Sensitivity Analysis module 230, and a Pump ScheduleDriven Diameter and Discharge Coefficient module 231.

In some embodiments, the Optimizer module 220 optimizes the perforationdesign to achieve uniform fluid distribution in multiple clusters, andtarget perforation friction pressure for limited entry. The Optimizermodule 120 includes a Calculate Fluid Distribution in clusterssub-module 222, a Determine Hole Count sub-module 223, a Determine HoleCount & Pump Rate sub-module 226, a Determine Hole Count & Hole Sizesub-module 227, and a Determine Hole Count (HC), Hole Size (HS) & PumpRate sub-module 228. In some embodiments, the Calculate FluidDistribution in clusters sub-module 222 contains a set of instructions222-1 and accepts metadata and parameters 222-2 that will enable it tocalculate fluid distribution in perforation clusters. In someembodiments, the Determine Hole Count sub-module 223 contains a set ofinstructions 223-1 and accepts metadata and parameters 223-2 that willenable it to determine (e.g., optimize) hole count. In some embodiments,the Determine Hole Count & Pump Rate sub-module 226 contains a set ofinstructions 226-1 and accepts metadata and parameters 226-2 that willenable it to determine hole count and pump rate. In some embodiments,the Determine Hole Count (HC), Hole Size (HS) & Pump Rate sub-module 228contains a set of instructions 228-1 and accepts metadata and parameters228-2 that will enable it to determine hole count, hole size, and pumprate. As an example, a human user may be presented with an optioncorresponding to the sub-module 223, an option corresponding to thesub-module 226, and an option corresponding to the sub-module 227 viathe user interface 205. The input and output of each sub-module may bedifferent (although there may be some overlap), and the relevant inputand output may depend on the option selected by the human user.

In some embodiments, the Well Level Optimization module 229 contains aset of instructions 229-1 and accepts metadata and parameters 229-2 thatwill enable it to optimize perforation design in multiple segments oflong lateral (e.g., multiple fracture stages) accounting for surfacepressure limitation (e.g., Pump-rate varies along lateral).

In some embodiments, the Sensitivity Analysis module 230 contains a setof instructions 230-1 and accepts metadata and parameters 230-2 thatwill enable it to calculate fluid distribution among multiple clustersfor different scenarios of net pressure, fracture height, or both (sinceboth parameters have a range of uncertainty). FIG. 4F illustrates aflowchart of one embodiment of method of determining a slurrydistribution per cluster for given perforation/completion design, forexample, using a sensitivity analysis module such as module 230.

In some embodiments, the Pump Schedule Driven Diameter and DischargeCoefficient module 231 contains a set of instructions 231-1 and acceptsmetadata and parameters 231-2 that will enable it to handle fixeddiameter and discharge coefficient. In some embodiments, the PumpSchedule Driven Diameter and Discharge Coefficient module 231 contains aset of instructions 231-1 and accepts metadata and parameters 231-2 thatwill enable it to handle variable diameter and discharge coefficient.

The system 200 may also include at least one Data module or sub-module232, which handles the data. This data may be supplied by the Datamodule or sub-module 232 to other modules and/or sub-modules. Forexample, the data may be inputted by an operator via the user interface205, received from one or more sensors or devices, received from one ormore system of records, etc. In some embodiments, the output of each ofthe modules and/or sub-modules may be provided to an operator or toanother system(s), for example, via the user interface 205, the networkcommunication module 218, a printer, the display 205-1, a data storagedevice, any combination of thereof, etc.

In some embodiments, one or more module (or sub-module(s) thereof) mayaim to create equal fracture geometry with equal fluid distribution ineach cluster. In some embodiments, one or more module (or sub-module(s)thereof) may aim to create substantially equal fracture geometry withsubstantially equal fluid distribution in each cluster. Substantiallyequal may be plus or minus a percentage for a target in someembodiments.

Although specific operations have been identified for the sub-modulesdiscussed herein, this is not meant to be limiting. Each sub-module maybe configured to execute operations identified as being a part of othersub-modules, and may contain other instructions, metadata, andparameters that allow it to execute other operations of use inprocessing data and generating hydrocarbon production forecasts. Forexample, any of the sub-modules may optionally be able to generate adisplay that would be sent to and shown on the user interface display205-1. In addition, any of the data or processed data products may betransmitted via the communication interface(s) 203 or the networkinterface 208 and may be stored in memory 206.

Method 300 is, optionally, governed by instructions that are stored incomputer memory or a non-transitory computer readable storage medium(e.g., memory 206) and are executed by one or more processors (e.g.,processors 202) of one or more computer systems. The computer readablestorage medium may include a magnetic or optical disk storage device,solid state storage devices such as flash memory, or other non-volatilememory device or devices. The computer readable instructions stored onthe computer readable storage medium may include one or more of: sourcecode, assembly language code, object code, or another instruction formatthat is interpreted by one or more processors. In various embodiments,some operations in each method may be combined and/or the order of someoperations may be changed from the order shown in the figures. For easeof explanation, method 300 is described as being performed by a computersystem, although in some embodiments, various operations of method 300are distributed across separate computer systems.

Turning to FIG. 3, this figure illustrates one embodiment of a method ofdetermining a hydraulic fracture completion configuration for a wellborethat extends through a subterranean formation, such as a method 300. Themethod 300 of FIG. 3 may be executed by the system 200 of FIG. 2 andexamples will be utilized to discuss some portions of the method 300. Insome embodiments, the hydraulic fracture completion configurationcomprises a limited entry perforation completion. In some embodiments,the hydraulic fracture completion configuration comprises a variableshot cluster perforation completion. In some embodiments, the hydraulicfracture completion configuration comprises a uniform shot clusterperforation completion. In some embodiments, the wellbore has aninclination greater than 60 degrees from vertical (e.g., 61 degrees-90degrees, 65 degrees-75 degrees, 65 degrees-85 degrees, 65 degrees-90degrees, or 75 degrees-90 degrees). In some embodiments, the wellborecomprises a horizontal wellbore. In some embodiments, the wellborecomprises a vertical wellbore.

In some embodiments, the hydraulic fracture completion configuration isutilized to perform a hydraulic fracturing operation on the wellbore.For example, a perforation gun may be utilized to generate, in thewellbore, the determined quantity of perforation clusters in theplurality of the perforation clusters within the fracture stage. Forexample, a perforation gun or other device(s) may be utilized togenerate, in the wellbore, the determined quantity of perforation holesfor each perforation cluster of the plurality of perforation clusterswithin the fracture stage. For example, a perforation gun may beutilized to generate, in the wellbore, the determined diameter of theperforation holes for each perforation cluster of the plurality ofperforation clusters within the fracture stage, and so on.

At 305, the method 300 includes calculating a stress profile across aplurality of perforation clusters within a fracture stage of thewellbore.

In one embodiment, the stress profile comprises a minimum horizontalstress profile. The minimum horizontal stress profile across theplurality of perforation clusters within the fracture stage of thewellbore is calculated using an equation:

${\Delta\sigma_{x}} = {p_{n}\lbrack {1 - \frac{x^{3}}{( {{h_{f}^{2}/4} + x^{2}} )^{3/2}}} \rbrack}$

where p_(n) represents the fracture net pressure, x represents adistance between each perforation cluster of the plurality ofperforation clusters within the fracture stage and a closest perforationcluster within an adjacent fracture stage, and h_(f) represents afracture height.

In one embodiment, the stress profile comprises an initial stressprofile or changes thereto induced by a hydraulic fracturing operation,fluid depletion in the subterranean formation, one or more otherwellbore operations, or any combination thereof. The changes to theinitial stress profile induced by the hydraulic fracturing operationcomprises hydraulic fracturing within the fracture stage in thewellbore, hydraulic fracturing in an adjacent fracture stage in thewellbore, hydraulic fracturing in a neighboring wellbore, or anycombination thereof. Changes in stress profile may be referred to as“stress shadow”. Stress shadow is discussed in US Publication No.2016/0003020 and US Publication No. 20120325462, each of which isincorporated by reference. The stress shadow may be calculated using ananalytical equation:

$\sigma_{x} = {p_{n}\lbrack {1 - \frac{x^{3}}{( {{h_{f}^{2}/4} + x^{2}} )^{3/2}}} \rbrack}$

Sneddon, I. N., 1946, “The Distribution of Stress in the Neighborhood ofa Crack in an Elastic Solid”, Proc. R. Soc. Lond. A 187, 229-260, whichis incorporated by reference. FIG. 5 illustrates the stress shadow incontext. FIG. 6 also illustrates proppant concentration profiles for aheel cluster and a toe cluster.

At 310, the method 300 includes calculating a fracture pressureparameter for each perforation cluster of the plurality of perforationclusters within the fracture stage of the wellbore as a function of thestress profile across the plurality of perforation clusters within thefracture stage, a perforation friction that accounts for perforationhole erosion, a fracture net pressure, and a fracture closure pressure.

In one embodiment, the fracture pressure parameter for each perforationcluster of the plurality of perforation clusters within the fracturestage of the wellbore is calculated using an equation:

P _(wellbore) =P _(stress shadow) +P _(perf) +P _(net) +P _(closure)

where P_(stress shadow) represents a change in the stress profile acrossthe plurality of perforation clusters within the fracture stage,P_(perf) represents the perforation friction that accounts forperforation hole erosion, P_(net) represents the fracture net pressure,and P_(closure) represents the fracture closure pressure.

As an example, assume a particular fracture stage includes 4 perforationclusters. P_(wellbore) at cluster1 equals P_(stress shadow) atcluster1+P_(perf) at cluster1+P_(net) at cluster1+P_(closure) atcluster1. P_(wellbore) at cluster2 equals P_(stress shadow) atcluster2+P_(perf) at cluster2+P_(net) at cluster2+P_(closure) atcluster2. P_(wellbore) at cluster3 equals P_(stress shadow) atcluster3+P_(perf) at cluster3+P_(net) at cluster3+P_(closure) atcluster3. P_(wellbore) at cluster4 equals P_(stress shadow) atcluster4+P_(perf) at cluster4+P_(net) at cluster4+P_(closure) atcluster4. Afterwards, P_(perf) (defined by injection rate and hole countfor example) for cluster1 may be adjusted, P_(perf) (defined byinjection rate and hole count for example) for cluster2 may be adjusted,P_(perf) (defined by injection rate and hole count for example) forcluster3 may be adjusted, P_(perf) (defined by injection rate and holecount for example) for cluster4 may be adjusted, or any combinationthereof such that the P_(wellbore) for cluster1, P_(wellbore) forcluster2, P_(wellbore) for cluster3, and P_(wellbore) for cluster4 aresubstantially equal. In this particular example, P_(closure), P_(net),and P_(stress shadow) are not changed. However, those of ordinary skillin the art will appreciate that various modifications are possible. Forexample, in some embodiments, both P_(stress shadow) and P_(perf) may beadjusted in order to equalize the P_(wellbore) for the variousperforation clusters.

In one embodiment, the perforation friction that accounts forperforation hole erosion is calculated using an equation:

$P_{perf} = \frac{{0.2}369\mspace{11mu} q^{2}\rho_{f}}{C_{D}^{2}N_{p}^{2}d_{p}^{4}}$

where q represents an injection rate into each perforation cluster,ρ_(f) represents an injection fluid density, C_(D) represents aperforation discharge coefficient, N_(p) represents the quantity ofperforation holes for each perforation cluster of the plurality ofperforation clusters, and d_(p) represents the diameter of theperforation holes for each perforation cluster of the plurality ofperforation clusters within the fracture stage.

In one embodiment, the perforation friction that accounts forperforation hole erosion comprises an average perforation frictioncalculated at multiple time steps.

In one embodiment, the fracture closure pressure comprises a minimumhorizontal stress.

In one embodiment, the fracture pressure parameter for each perforationcluster of the plurality of perforation clusters within the fracturestage of the wellbore is further calculated as a function of fractureheight.

At 315, the method 300 includes determining a quantity of perforationclusters in the plurality of the perforation clusters within thefracture stage, a quantity of perforation holes for each perforationcluster of the plurality of perforation clusters within the fracturestage, a diameter of the perforation holes for each perforation clusterof the plurality of perforation clusters within the fracture stage, aspacing between each perforation cluster of the plurality of perforationclusters within the fracture stage, an injection distribution across theplurality of perforation clusters within the fracture stage, or anycombination thereof, for the hydraulic fracture completion configurationbased on the calculated fracture pressure parameters.

In one embodiment, determining based on the calculated fracture pressureparameters comprises iteratively adjusting the calculated fracturepressure parameters to reduce a variation in a distribution of thecalculated fracture pressure parameters for the plurality of theperforation clusters within the fracture stage.

In one embodiment, determining based on the calculated fracture pressureparameters comprises iteratively adjusting the calculated fracturepressure parameters to identify the hydraulic fracture completionconfiguration with a closest match between a distribution of thecalculated fracture pressure parameters for the plurality of theperforation clusters within the fracture stage to a targeteddistribution of calculated fracture pressure parameters for theplurality of the perforation clusters within the fracture stage. Theclosest match between the distribution of the calculated fracturepressure parameters for the plurality of the perforation clusters withinthe fracture stage to the targeted distribution of calculated fracturepressure parameters for the plurality of the perforation clusters withinthe fracture stage is determined based on a cumulative deviation betweenthe perforation friction, a total injection rate for the plurality ofperforation clusters within the fracture stage, an injection rateallocation for the plurality of perforation clusters within the fracturestage, or any combination thereof.

In one embodiment, determining based on the calculated fracture pressureparameters comprises iteratively adjusting the calculated fracturepressure parameters to reduce a variation in the injection distributionacross the plurality of perforation clusters within the fracture stage.

In one embodiment, determining based on the calculated fracture pressureparameters comprises iteratively adjusting the calculated fracturepressure parameters to identify the hydraulic fracture completionconfiguration with a closest match between the injection distributionacross the plurality of perforation clusters within the fracture stageto a target injection distribution across the plurality of perforationclusters within the fracture stage. The closest match between theinjection distribution across the plurality of perforation clusterswithin the fracture stage to the target injection distribution acrossthe plurality of perforation clusters within the fracture stage isdetermined based on a cumulative deviation between the perforationfriction, a total injection rate for the plurality of perforationclusters within the fracture stage, an injection rate allocation for theplurality of perforation clusters within the fracture stage, or anycombination thereof.

As an example, in one embodiment, determining the quantity ofperforation holes for each perforation cluster of the plurality ofperforation clusters within the fracture stage further comprises usingparameters to represent a quantity of perforation clusters within thefracture stage, a spacing between the quantity of perforation clusterswithin the fracture stage, a diameter of the perforation holes for thequantity of perforation clusters within the fracture stage, aperforation hole erosion value, a perforation friction pressure target,a perforation phasing configuration, an injection pump rate, aninjection fluid density, a fracture net pressure, a fracture height, anda fracture closure pressure. The term “using” could be inputting,prepopulating, receiving, or any other method to define these parametersin the tool.

As an example, in one embodiment, determining the injection distributionacross the plurality of perforation clusters within the fracture stagefurther comprises using parameters to represent a quantity ofperforation clusters within the fracture stage, a spacing between thequantity of perforation clusters within the fracture stage, a diameterof the perforation holes for the quantity of perforation clusters withinthe fracture stage, the quantity of perforation holes for the quantityof perforation clusters within the fracture stage, a perforation holeerosion value, a perforation phasing configuration, an injection pumprate, an injection fluid density, a fracture net pressure, a fractureheight, and a fracture closure pressure. The term “using” could beinputting, prepopulating, receiving, or any other method to define theseparameters in the tool.

In some embodiments, the method 300 includes performing a sensitivityanalysis on the hydraulic fracture completion configuration usingcombinations of multiple values of the fracture net pressure, offracture height, or both. FIG. 13 illustrates one embodiment ofsensitivity analysis output. FIG. 14 illustrates another embodiment ofsensitivity analysis output. FIG. 4F illustrates a flowchart of oneembodiment of method of determining a slurry distribution per clusterfor given perforation/completion design, for example, using asensitivity analysis module such as the module 230. FIG. 26 alsoillustrates a screenshot related to sensitivity analysis.

Regarding injection pump rate, in some embodiments, the method 300includes determining an injection pump rate across the plurality ofperforation clusters within the fracture stage for the hydraulicfracture completion configuration. In some embodiments, determining theinjection pump rate across the plurality of perforation clusters withinthe fracture stage further comprises using parameters to represent aminimum injection pump rate, a maximum injection pump rate, a minimumdiameter of the perforation holes for the quantity of perforationclusters within the fracture stage, and a maximum diameter of theperforation holes for the quantity of perforation clusters within thefracture stage. The term “using” could be inputting, prepopulating,receiving, or any other method to define these parameters in the tool.In some embodiments, the method 300 includes determining an injectionpump rate across at least one additional fracture stage for thehydraulic fracture completion configuration. For example, the injectionpump rate across at least one additional fracture stage may bedetermined in a similar manner as indicated above.

Regarding friction loss, in some embodiments, the method 300 includescalculating a friction loss limit for the fracture stage of thewellbore. In some embodiments, the method 300 includes calculating afriction loss limit for at least one additional fracture stage for thehydraulic fracture completion configuration. In some embodiments, thefriction loss limit is calculated based on a maximum allowable surfacepressure, a hydrostatic pressure, the fracture net pressure, thefracture closure pressure, a net wellbore pressure, a target perforationfriction, or any combination thereof. In some embodiments, the method300 includes calculating an injection pump rate for each fracture stageof the wellbore based on the friction loss limit. In some embodiments,the method 300 includes updating the hydraulic fracture completionconfiguration based on the injection pump rate for each fracture stageof the wellbore.

As indicated hereinabove, some embodiments may involve multiple fracturestages. Thus, in some embodiments, the method 300 may includecalculating the stress profile across the plurality of perforationclusters for multiple fracture stages of the wellbore; calculating thefracture pressure parameter for each perforation cluster of theplurality of perforation clusters for the multiple fracture stages ofthe wellbore; and determining the quantity of perforation clusters inthe plurality of the perforation clusters for the multiple fracturestages, the quantity of perforation holes for each of the plurality ofperforation clusters for the multiple fracture stages, the diameter ofthe perforation holes for each perforation cluster of the plurality ofperforation clusters for the multiple fracture stages, the spacingbetween each perforation cluster of the plurality of perforationclusters for the multiple fracture stages, the injection distributionacross the plurality of perforation clusters for the multiple fracturestages, or any combination thereof, for the hydraulic fracturecompletion configuration based on the calculated fracture pressureparameter for each perforation cluster of the plurality of perforationclusters for the multiple fracture stages of the wellbore.

At 320, the method 300 may also include determining a layout for theperforation holes of each perforation cluster of the plurality ofperforation clusters within the fracture stage for the hydraulicfracture completion configuration and/or determining a layout for theperforation holes of each perforation cluster of at least one otherfracture stage for the hydraulic fracture completion configuration. Insome embodiments, determining the layout includes determiningorientation (e.g., azimuth) of at least one perforation hole. In someembodiments, determining the layout includes obtaining a more uniformfluid distribution across perforation clusters, obtaining a more uniformproppant distribution across perforation clusters, or any combinationthereof. In some embodiments, determining the layout includes optimizingfluid distribution (e.g., towards more uniform), optimizing proppantdistribution (e.g., towards more uniform), or any combination thereof.For example, determining the layout may include determining the locationof the perforation holes on the wellbore. The term optimizing mayinclude improving, determining (e.g., determining location of aperforation hole(s) that leads to more uniform), etc. In someembodiments, 320 may be performed after 315, as illustrated in FIG. 3.Layout examples are illustrated in the FIGS. 15A, 15B, 15C, and 15D. Forexample, FIG. 15B illustrates at cluster location2: four perforationholes with two perforation holes towards the top of wellbore crossectionand with two perforation holes towards the bottom of the wellborecrosscection. On the other hand, at cluster location5, four perforationholes are illustrated towards the bottom of the wellbore crossection. Onthe other hand, at cluster locations 1 and 3, four perforations holesare illustrated with one perforation hole towards the top of thewellbore crossection and three perforation holes towards the bottom ofthe wellbore crossection.

FIG. 1B illustrates one example with an aim to create equal fracturegeometry with equal fluid distribution in each cluster. FIGS. 16-28illustrate various screenshots and output that may be generatedconsistent with the instant disclosure. FIGS. 4A-4G illustrate variousflowcharts of various embodiments of methods consistent with theprinciples of the present disclosure. Furthermore, embodimentsconsistent with the principles of the present invention may be performedafter one or more perforations holes have been made in the wellbore(e.g., after a fracture stage has been completed) so as to improve thesubsequent fracture stage or subsequent fracture stages, and in thisscenario, data from this wellbore may be utilized. Additionally,embodiments consistent with the principles of the present invention maybe performed before any perforations holes have been made in thewellbore so as to improve the first fracture stage (and potentially thesubsequent fracture stage or subsequent fracture stages), and in thisscenario, data from a neighboring wellbore(s) and/or from thesubterranean formation may be utilized.

Additionally, FIGS. 16-28 illustrate various screenshots and output thatmay be generated consistent with the instant disclosure. Indeed, aperson of ordinary skill in the art may appreciate the negative impactof non-uniform fracture fluid distribution/placement across each clusterdue to variation in stress profile across each cluster behind wellborein formation because of stress shadow and other heterogeneity. Thedifferent stress across each cluster location results in varying fluiddistribution/placement across each cluster and inside each fractureduring hydraulic fracturing treatment. However, the embodiments providedherein may be utilized for calculation of stress shadow for the givenwell completion design as function of fracture parameters (fractureheight, net pressure) and fracture placement design (cluster spacing,number of clusters per fracture stage). Using the perforation design(perforation friction) to counter the stress shadow with aim to achieveuniform stress environment across all cluster so uniform fracture fluiddistribution can be achieved. The key optimized parameters areperforation diameter, perforation hole count per cluster, fracture pumprate, and its variation accounting for change in perforation diameterwith proppant erosion.

PROPPANT DISTRIBUTION: Multi-stage fracturing is one of the mostcommonly used completion methods for horizontal wellbores inunconventional reservoirs. However, the proppant is commonly unevenlydistributed across the perforation clusters in each stage, with a fewclusters taking most of the injected proppant. This inefficient proppantplacement is very likely to result in inadequate reservoir stimulationand poor well performance. Computational Fluid Dynamics (CFD) is anumerical method capable of modeling proppant transport in horizontalwellbores with great detail. CFD can be used to improve perforation andfracturing designs and achieve near-uniform proppant distribution alonga stimulation stage. However, regardless of its robustness, conducting aDOE (design of experiments) using CFD modeling of two-phase fluid-solidflow is challenged by the very expensive computational cost when afull-scale stage with long laterals is modeled. Although someconventional processes can be used to accelerate CFD calculations andDOE, these conventional processes do not really account for the fullimpact of azimuth.

Indeed, non-uniform proppant distribution/placement as compared tofracture fluid distribution/placement across each cluster in wellboredue to variation in fluid and proppant dynamics in horizontal wellborebecause of combined effect of gravity settling and proppant particlemomentum (proppant and fluid not travelling together) and its variationacross wellbore is challenging. In a horizontal wellbore, fluid andmixed proppant do not travel together as gravity settling and momentummechanism of proppant impact the proppant particle's distribution withinthe fracture fluid slurry, and results in variation in concentration ofproppant particles across cross-section as well as along wellbore (fromtoe to heel). With multiple perforation clusters and multipleperforation hole in each cluster, as the fluid and proppant exitwellbore through each perforation hole, it changes the flow dynamics(reduced velocity) impacting the proppant settling rate along withproppant momentum. The location of perforation across wellborecircumference (perforation azimuth such as top, bottom or any otherangle from top) significantly impact the ratio of proppant particle influid exiting each of perforation hole.

CFD model can be used to study the impact of fluid and proppant dynamicsin horizontal wellbore for well-defined cluster design (clusterspacing), perforation design (location, count, diameter), flowparameters (injection rate and fluid distribution across eachperforation), fracture fluid properties (viscosity) and proppantproperties (diameter, specific gravity, concentration) to evaluate theproppant and fluid distribution ratio for individual perforation andcluster. But, this modeling process takes 3-5 days to evaluate eachspecific case, and finding an optimum solution of perforation azimuth(location across circumference) for each perforation in each cluster toachieve uniform proppant distribution in addition to uniform fluiddistribution is challenging. To reduce the modeling process time andthereby achieving optimum solution of perforation azimuth (locationacross circumference) for each perforation in each cluster to achieveuniform proppant distribution in addition to uniform fluid distribution,the embodiments provided herein have made some changes.

Provided herein are various embodiments of determining proppantdistribution for a plurality of clusters within a fracture stage of awellbore. The embodiments discussed herein may more efficientlydetermine proppant distribution during hydraulic fracture along a fullmulti-cluster stage based on correlations (e.g., model) developed fromCFD modeling results from a single perforation. First, the embodimentsprovided herein model a horizontal pipe with only a single perforationor several perforations at the same azimuth to calculate proppantefficiency with various input parameters. The proppant efficiency forperforations at other azimuths can be determined quickly and accuratelybased on the obtained concentration and velocity profiles alongtransverse cross-sections. Thus, a single cluster CFD model andmethodology may be utilized to determine proppant efficiency for anyperforation azimuth. Secondly, in embodiments provided herein, CFDmodels have a long lateral at the inlet to ensure an equilibrium stateis achieved before reaching the perforation(s). This allows the effectof perforation azimuth on proppant efficiency to be sufficientlyincorporated into the developed correlations. The capability ofdetermining proppant distribution along a multi-cluster stage based onsingle perforation CFD modeling may accelerate the CFD modeling anddecision-making processes for unconventional assets.

Advantageously, embodiments consistent with the instant disclosure mayutilize a CFD Model setup of at least one opening along a single azimuthto provide answers in seconds instead of days. The setup includes atleast 100-ft long pipe before the perforations, for example. The singleazimuth may be used to determine proppant efficiency at arbitraryazimuth based on CFD modeling results. The number of CFD models requiredfor correlation development may even be reduced by about 85%. The model(correlation) between proppant efficiency and key parameters wasdeveloped based on machine learning. This model has been validatedagainst full stage CFD modeling results. By using this model, proppantdistribution along a stage may be obtained seconds, as compared toseveral days by running full stage CFD models.

One embodiment of a computer-implemented method of determining proppantdistribution for a plurality of clusters within a fracture stage of awellbore is illustrated in FIG. 29 as a method 2900. The method 2900 maybe executed by the system of FIG. 2. The system 200 may include aproppant distribution module 250 that execute the operations of themethods shown in the figures related to proppant distribution. Theproppant distribution module 250 may include a CFD sub-module 290, aproppant efficiency sub-module 270, a model sub-module 280, a proppantdistribution sub-module 260, a multiplier sub-module 296, a data moduleor sub-module 295.

In some embodiments, the CFD sub-module 290 sub-module 290 contains aset of instructions 290-1 and accepts metadata and parameters 290-2 thatwill enable it to perform computational fluid dynamics modeling on atleast a portion of a wellbore without any openings and a portion of thewellbore comprising at least one opening along a single azimuth todetermine proppant efficiency for the at least one opening along thesingle azimuth while simulating flow of fluid, proppant, or anycombination thereof through the wellbore, an equilibrium proppantconcentration profile for the portion of the wellbore without anyopenings, and an equilibrium velocity profile for the portion of thewellbore without any openings. In some embodiments, the proppantefficiency sub-module 270 contains a set of instructions 270-1 andaccepts metadata and parameters 270-2 that will enable it to determineproppant efficiency for at least one other opening of the wellbore at adifferent azimuth using the determined proppant efficiency for the atleast one opening along the single azimuth, the determined equilibriumproppant concentration profile for the portion of the wellbore withoutany openings, and the determined equilibrium velocity profile for theportion of the wellbore without any openings. In some embodiments, themodel sub-module 280 contains a set of instructions 280-1 and acceptsmetadata and parameters 280-2 that will enable it to generate a modelthat correlates the single azimuth, the determined proppant efficiencyfor the at least one opening along the single azimuth, and thedetermined proppant efficiency for the at least one other opening of thewellbore at the different azimuth. In some embodiments, the proppantdistribution sub-module 260 contains a set of instructions 260-1 andaccepts metadata and parameters 260-2 that will enable it to use themodel to determine proppant distribution for the plurality of clusterswithin the fracture stage of the wellbore. In some embodiments, themultiplier sub-module 296 contains a set of instructions 296-1 andaccepts metadata and parameters 296-2 that will enable it to determinethe multiplier to account for the cluster spacing between the pluralityof clusters within the fracture stage of the wellbore.

The system 200 may also include at least one Data module or sub-module295 (e.g., similar to Data module or sub-module 232), which handles thedata. This data may be supplied by the Data module or sub-module 295 toother modules and/or sub-modules. For example, the data may be inputtedby an operator via the user interface 205, received from one or moresensors or devices, received from one or more system of records, etc. Insome embodiments, the output of each of the modules and/or sub-modulesmay be provided to an operator or to another system(s), for example, viathe user interface 205, the network communication module 218, a printer,the display 205-1, a data storage device, any combination of thereof,etc.

Returning to the method 2900, FIG. 30 illustrates one embodiment of ahorizontal wellbore with multiple stages. FIG. 30 also illustrates thateach stage may have multiple perforation clusters and clusters may havedifferent perforation counts and azimuths. As illustrated in FIG. 31A,conventionally, a CFD model of a full stage may be run to obtain theproppant distribution along this stage, but this typically verytime-consuming and takes several days. However, as discussed furtherherein, the method 2900 may be utilized to develop a machine learningmodel that is used to obtain the proppant distribution along a fullstage in seconds. In one embodiment, the method 2900 utilizes CFD modelswith a different setup, for example, as illustrated in FIG. 31B with a100-ft long pipe. The discussion may utilize the term “perforation”,“perf” or the like for simplicity, but the term “opening” in the method2900 may be a perforation, an opening in a sleeve, an opening in aliner, etc.

At 2905, the method 2900 includes performing computational fluiddynamics modeling on at least a portion of a wellbore without anyopenings and a portion of the wellbore comprising at least one openingalong a single azimuth to determine proppant efficiency for the at leastone opening along the single azimuth while simulating flow of fluid,proppant, or any combination thereof through the wellbore, anequilibrium proppant concentration profile for the portion of thewellbore without any openings, and an equilibrium velocity profile forthe portion of the wellbore without any openings. In one embodiment,determining the equilibrium proppant concentration profile and theequilibrium velocity profile by the CFD modeling includes a lengthcondition. For example, the portion of the wellbore without any openingsthat is located upstream of the portion of the wellbore comprising theat least one opening along the single azimuth is at least 100 feet inlength (e.g., at least 150 feet, at least 200 feet, at least 300 feet,at least 350 feet, or at least 400 feet) to provide an equilibriumstate. In some embodiments, the length is 3000 feet or less (e.g., 2500feet or less, 2000 feet or less, 1500 feet or less, 1000 feet or less,750 feet or less, 450 feet or less, 400 feet or less, 350 feet or less,300 feet or less, 250 feet or less, 200 feet or less, or 150 feet orless). The length can range from any of the minimum values describedabove to any of the maximum values described above. For example, in someembodiments, the length can be of from 100 feet to 3000 feet (e.g., offrom 100 feet to 200 feet or of from 100 feet to 500 feet). In oneembodiment, the length is about 100 feet as illustrated in FIG. 32. Thesingle azimuth may be practically any degree, such as, but not limitedto 0°, 30°, 60°, 90°, 120°, 150°, 180°, 210°, 240°, 270°, 300°, or330°.

One embodiment may include using wellbore properties, fluid properties,and proppant properties in determining the proppant efficiency for theat least one opening along the single azimuth, determining theequilibrium proppant concentration profile for the portion of thewellbore without any openings, determining the equilibrium velocityprofile for the portion of the wellbore without any openings, or anycombination thereof. For example, the wellbore properties comprisewellbore diameter, perforation number, perforation diameter, flow ratethrough each perforation, and flow rate in the wellbore. For example,the fluid properties comprise fluid viscosity. The proppant propertiescomprise proppant concentration and proppant size. These examples arenon-limiting and one property may be affiliated with a differentcategory than illustrated.

For example, the CFD results may be generated by running single perfazimuth models with various combinations of the following parameters(DOE) in Table 1 below:

TABLE 1 Flow rate in wellbore, Q Flow rate through each perf, q Fluidviscosity (two values at two different shear rates), μ Proppantconcentration, c Proppant size, D_(prop) Perf diameter, D_(perf)Wellbore diameter, D_(well) Perf number, Perf_num Perf azimuth,Perf_azimuth

CFD modeling is discussed further in the following: (a) Bokane, A. B.,Jain, S., & Crespo, F. (2014, Sep. 30). Evaluation and Optimization ofProppant Distribuion in Multistage Fractured Horizontal Wells: ASimulation Approach. Society of Petroleum Engineers. SPE 171581-MS (b)Wu, C-H., Yi, S. S., & Shama, M. M. (217, Jan. 24 Proppam DistributionAmong Multiple Perforation Clusters in a Horizontal Wellbore. Society ofPetroleumi Egineers. SPE 184861-MS, (c) Alrnulhim, A., Kebert, B.,Miskiinirs, J., Humer, W., & Soehner, G. (2020, Jan. 28). Field-ScaleComputational Fluid Dynamics CFD Modeling of Proppant Transport andDistribution Within a Horizontal Hydraulic Fracturing Stage. Society ofPetroleum Engineers. SPE 199727-MS, each of which is incorporated byreference. Proppant efficiency refers to proppant concentration ofslurry exiting from an opening (e.g., openingA) divided by proppantconcentration in the wellbore upstream of the opening (e.g., openingA).FIG. 31B illustrates openings along a single azimuth. Proppantconcentration equals proppant weight divided by fluid volume.

During hydraulic fracturing treatments in horizontal wellbores, proppantladen slurry travels thousands of feet along the vertical section of thewellbore before reaching the landing zone. From there, it continues totravel horizontally for many thousands of feet to reach the first stageat the toe or a few hundreds of feet to reach the last stage at theheel. Therefore, a long horizontal lateral prior to each stage is usefulin the CFD computational domain. For that, a CFD model having a 300-fthorizontal pipe with an ID of 4.276-in was constructed to evaluate theminimum lateral length before each stage. The results in FIG. 33illustrates that a 100-ft pipe segment ahead of each stage issufficient.

At 2910, the method 2900 includes determining proppant efficiency for atleast one other opening of the wellbore at a different azimuth using thedetermined proppant efficiency for the at least one opening along thesingle azimuth, the determined equilibrium proppant concentrationprofile for the portion of the wellbore without any openings, and thedetermined equilibrium velocity profile for the portion of the wellborewithout any openings. For example, the proppant efficiency may bedetermined for arbitrary perf azimuth (Perf_azimuth) based on the CFDresults of 2905. Streamline envelope size (SES) may be utilized asexplained hereinbelow.

In one embodiment, determining the proppant efficiency for the at leastone other opening of the wellbore at the different azimuth includesdetermining streamline envelope size of a fluid using an equationcomprising:

SES of fluid−>Q _(perf)×(1−C _(perf))=∫_(A) ₁ [v _(ep)×(1−c_(ep))]dA  (i)

where Q_(perf) represents flowrate (e.g., slurry flowrate) through anopening, C_(perf) represents proppant volumetric fraction exiting theopening (e.g., exiting the opening mentioned for Q_(perf)), v_(ep)represents flow velocity at equilibrium, c_(ep) represents proppantvolumetric fraction at equilibrium, and A₁ represents cross-sectionalarea contained by a streamline envelope of the fluid. The equation (i)may be utilized for the opening at the single azimuth.

In one embodiment, determining the proppant efficiency for the at leastone other opening of the wellbore at the different azimuth includesdetermining streamline envelope size of proppant using an equationcomprising:

SES of proppant->Q _(perf) ×C _(perf)=∫_(A) ₂ (v _(ep) ×c _(ep))dA  (ii)

where Q_(perf) represents flowrate (e.g., slurry flowrate) through anopening, C_(perf) represents proppant volumetric fraction exiting theopening (e.g., exiting the opening mentioned for Q_(perf)), v_(ep)represents the flow velocity at equilibrium, c_(ep) represents proppantvolumetric fraction at equilibrium, and A₂ represents thecross-sectional area contained by a streamline envelope of the proppant.The equation (i) may be utilized for the opening at the single azimuth.

In one embodiment, both equations (i) and (ii) may be utilized fordetermining proppant efficiency for at least one other opening of thewellbore at a different azimuth.

FIG. 34 illustrates fluid streamline (grey color) and proppantstreamline (black color) exiting through the perforation, as well asproppant concentration profile (equilibrium state) along a cross-sectionof the wellbore. FIG. 35 illustrates SES of both proppant and fluid donot change with perforation azimuth, if the other parameters are thesame. The streamline envelope size (SES) of the proppant is alwayssmaller than that of fluid in the illustrated embodiment.

FIG. 36 illustrates one embodiment of an equilibrium proppantconcentration profile for the portion of the wellbore without anyopenings. FIG. 36 illustrates one embodiment of A₁ and A₂, with A₁ beingthe streamline envelope of the fluid and A₂ being the streamlineenvelope of the proppant. SES of both fluid and proppant are constantfor different perforation azimuths. FIG. 36 illustrates one embodimentof an equilibrium velocity profile for the portion of the wellborewithout any openings.

FIG. 37 illustrates examples validating proppant efficiency determinedfor at least one other opening of the wellbore at a different azimuth.Based on CFD results with perf of 0° phasing, FIG. 37 predicts sandconcentration for perfs of different orientations, and then compared thepredicted results with the CFD modeling results.

At 2915, the method 2900 includes generating a model that correlates thesingle azimuth, the determined proppant efficiency for the at least oneopening along the single azimuth, and the determined proppant efficiencyfor the at least one other opening of the wellbore at the differentazimuth. The model may be generated, including trained and/or retrained,in a variety of ways. In one embodiment, the model is generated using amachine learning algorithm. In one embodiment, the model comprises asupervised machine learning algorithm. In one embodiment, the supervisedmachine learning algorithm comprises Gaussian process regression. In oneembodiment, the supervised machine learning algorithm comprises a neuralnetwork.

One embodiment may include using wellbore properties, fluid properties,and proppant properties in generating the model. For example, thewellbore properties comprise wellbore diameter, perforation number,perforation diameter, flow rate through each perforation, and flow ratein the wellbore. For example, the fluid properties comprise fluidviscosity. The proppant properties comprise proppant concentration andproppant size. These examples are non-limiting and one property may beaffiliated with a different category than illustrated. In oneembodiment, the model is generated using the following as defined inTable 1 below:

f(Q,q,μ,c,D _(prop) ,D _(perf) ,D _(well),Perf_(num),Perf_azimuth)

TABLE 1 Flow rate in wellbore, Q Flow rate through each perf, q Fluidviscosity (two values at two different shear rates), μ Proppantconcentration, c Proppant size, D_(prop) Perf diameter, D_(perf)Wellbore diameter, D_(well) Perf number, Perf_num Perf azimuth,Perf_azimuth

FIG. 38 illustrates one embodiment of response time of a machinelearning model. A machine learning model was developed between proppantefficiency and key parameters (e.g., as in Table 1) based on asufficiently large amount of data. For example, a large amount of datais a dataset that is large enough to ensure a high accuracy of thetrained model, e.g. R2>0.95. About 6000 cases were utilized in thedataset that led to the model of FIG. 38. Gaussian process regressionwas chosen to train the model, and the model of FIG. 38 had a R2 thatwas close to 1.

FIG. 39 illustrates example results of a trained model. Proppantefficiency for different pumping rate, flow rate through perforation,and proppant concentration are illustrated in FIG. 39. Other parametersof FIG. 39 include: (a) Viscosity: 3 cp (@511 1/s); (b) Viscosity: 4 cp(@170 1/s); (c) Prop size: 100 mesh; (d) Wellbore diameter: 4.28 in; (e)Perf number: 1; (f) Perf azimuth: 180°; and (g) Perf diameter: 0.3 in.

At 2920, the method 2900 includes using the model to determine proppantdistribution for the plurality of clusters within the fracture stage ofthe wellbore. FIG. 40 illustrates one embodiment of a flowchart of usingthe model to determine proppant distribution for the plurality ofclusters within the fracture stage of the wellbore.

FIG. 41 illustrates a graph with three examples (Cluster Total, BottomPerforation, and Top Perforation) showing proppant distributionsdetermined in a manner consistent with 2905-2920 (e.g., using thetrained model) and proppant distributions determined by conventionalfull stage CFD modeling. The examples of FIG. 41 include proppantdistribution along a full stage with 15 clusters and each cluster hastwo perforations—one at the top (0°) and one at the bottom (180).Moreover, the validation case parameters include the following: (a) 15ft*15 clusters, (b) 2 perfs each cluster (0°, 180°), (c) pumping rate:80 bpm, (d) Viscosity: 3 cp (@511 1/s), (e) Viscosity: 4 cp (@170 1/s),(f) Prop size: 100 mesh, (g) Prop conc: 1 ppg, (h) Wellbore diameter:4.28 in, and (i) Perf diameter: 0.42 in. The two curves for the ClusterTotal illustrate agreement between the trained model and the full stageCFD modelling. The two curves for the Bottom Perforation illustrateagreement between the trained model and the full stage CFD modelling.The two curves for the Top Perforation illustrate agreement between thetrained model and the full stage CFD modelling.

Optionally, at 2925, the model (of 2915) may be utilized to determine asecond proppant distribution for a second plurality of clusters within asecond fracture stage of the wellbore or a second wellbore.

Optionally, at 2930, where using the model to determine the proppantdistribution for the plurality of clusters within the fracture stage ofthe wellbore includes applying a multiplier to account for clusterspacing between the plurality of clusters within the fracture stage ofthe wellbore. Optionally, at 2935, the method 2900 includes determiningthe multiplier to account for the cluster spacing between the pluralityof clusters within the fracture stage of the wellbore. In oneembodiment, the portion of the wellbore without any openings that islocated downstream of the portion of the wellbore comprising the atleast one opening along the single azimuth is at least 40 feet inlength. The 40 foot length is utilized to determine the multiplier.

In one embodiment, the portion of the wellbore without any openings thatis located downstream of the portion of the wellbore comprising the atleast one opening along the single azimuth is at least 40 feet in length(e.g., at least 50 feet, at least 55 feet, at least 60 feet, at least 65feet, at least 70 feet, or at least 75 feet) to provide an equilibriumstate. In some embodiments, the length is 100 feet or less (e.g., 75feet or less, 70 feet or less, 65 feet or less, 60 feet or less, 55 feetor less, 50 feet or less, or 45 feet or less). The length can range fromany of the minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the length can be offrom 40 feet to 100 feet (e.g., of from 40 feet to 60 feet or of from 40to 75 feet). In one embodiment, the length is about 100 feet asillustrated in FIG. 32.

The model generated at 2915 assumes that an equilibrium state isachieved before the slurry arrives at each cluster along the full stage.For cases with relatively short cluster spacing (e.g., <10 ft) and lowfluid viscosity (e.g., <2 cP at 511 1/s of shear rate), a concentrationmultiplier may be used to relax this assumption. The multiplier may bedetermined using the concentration profiles collected from severallocations (e.g., six equally spaced locations) in the 40-ft long pipebefore the outlet, as illustrated in FIG. 42. In one embodiment, themultiplier is a function of distance from previous cluster, flow rate inwellbore, flow rate through previous cluster, fluid viscosity, proppantconcentration, proppant size, or any combination thereof.

In one embodiment, determining the multiplier and applying themultiplier may include: (a) concentration profiles may be collected fromsix locations after the cluster, (b) the difference of theseconcentration profiles from the equilibrium state may be calculated (seeFIG. 43), (c) multiplier may be developed based on the collected data(e.g., the multiplier is a function of distance from previous cluster,flow rate in wellbore, flow rate through previous cluster, fluidviscosity, proppant concentration, proppant size, or any combinationthereof), and (d) update proppant efficiency of each perforation bymultiplying the multiplier and the original proppant efficiency (i.e.,multiplier x original proppant efficiency). FIG. 43 illustrates thedifference in proppant concentration from equilibrium state in oneexample.

FIG. 44 illustrates a flowchart of one embodiment of a method of using amodel to determine the proppant distribution for the plurality ofclusters within the fracture stage of the wellbore includes applying amultiplier to account for cluster spacing between the plurality ofclusters within the fracture stage of the wellbore. Flowchart (withmultiplier) in FIG. 44 is a modified version of the embodiment of FIG.40.

A more thorough example is also provided below. The CFD model geometryis comprised of three parts: (i) a 100-ft long horizontal unperforatedpipe at the inlet, (ii) a short pipe segment perforated at the phasingof 270°, and (iii) another 40-ft long pipe following the perforatedsegment and before the outlet, such as the CFD model geometry in FIG.42. The EGM approach is used for the CFD modeling. Equilibriumconcentration and velocity profiles are collected at the transverseplane about 95 ft away from the inlet for all the CFD models. These 2Dprofiles are utilized to estimate proppant efficiency of perforations atarbitrary azimuth by the following steps: (a) After CFD modeling isfinished, collect slurry flowrate (Q_perf) and proppant volumetricfraction (C_perf) through the perforation(s) as well as the equilibriumconcentration (conc) and velocity (velocity) profiles; (b) Determinestreamline envelope size (SES) of fluid using equation (i); and (c)Determine SES of proppant using equation (ii). It is found that both offluid SES and proppant SES remain nearly unchanged with varyingperforation azimuth for the same input parameters. By utilizing thisfinding, the proppant efficiency for perforation with arbitrary azimuthis calculated based on the two equations. This methodology significantlyreduces the number of CFD models required to develop the correlations.

After completing CFD modeling with 270° perforation(s) with all designedparameters, proppant efficiencies for perforation of 0°-180° arecalculated using the method introduced above. Both the CFD modelingresults and the calculated results are employed to correlate proppantefficiency with key parameters, including pumping rate, flowrate throughthe perforation(s), proppant size, proppant concentration, fluidviscosity, perforation azimuth, perforation diameter, perforationnumber, and wellbore diameter. The developed correlations are used tocalculate proppant distribution along a full stage with arbitraryperforation number and azimuth for given fluid distribution values. Theprocedure is summarized below: Based on operational parameters and fluidand proppant properties, calculate proppant efficiency for perforationsin the first heel cluster; Record the amount of proppant received bythis cluster and update the downstream wellbore flowrate and proppantconcentration; Go to the subsequent cluster until the last one in toe isreached.

The process assumes that equilibrium state is achieved before slurryarriving at each cluster along the full stage. However, for relativelyshort cluster spacing, concentration multipliers (developed using theconcentration profiles collected from several locations in the 40-ftlong pipe before the outlet) is used to relax this assumption and makethis process more robust.

WELLBORE TO FRACTURE CONNECTIVITY APPARATUS: Conventional approacheshave suffered from an inability to predict plugging (e.g., partialplugging and complete plugging) of a perforation to fracture connectedregion, which has resulted in non-uniform fluid and proppantdistribution and/or placement. In multistage horizontal wellborefracturing, multiple hydraulic fractures are generated from eachperforation and cluster. The designed diameter of the perforation is ina range of 0.2-0.5 inch, whereas the fracture width is in a range of0.02-0.2 inch. As the fluid and proppant travel through the horizontalwellbore, especially across the different perforations and clusters,variation in proppant concentration across the cross-section as well asalong the horizontal wellbore (from toe to heel) tend to occur. Thenon-uniform fluid and proppant distribution and/or placement may therebybe caused by proppant settling and concentration variation for differentcluster design (e.g., cluster spacing), perforation design (e.g.,location, count, diameter), flow parameters (e.g., injection rate andfluid distribution across each perforation), fracture fluid properties(e.g., viscosity), and proppant properties (e.g., diameter, specificgravity, concentration).

Indeed, in unconventional horizontal wellbores, a typical hydraulicfracturing treatment is pumped through 5-15 perforation clusters in eachstage of plug-n-perf completion. For many of these unconventionalfracturing treatments, slickwater is commonly used as a carrier fluid totransport proppant. Due to low viscosity of slickwater and proppantgravity effects, proppant segregation (proppant concentration profilevariation within wellbore) and settling at the workstring bottom takeplace in the wellbore; in addition, proppant does not always follow thefluid streamline due to large inertia while entering a fracture througha perforation from wellbore.

FIG. 45 illustrates the distribution of proppant concentration acrossthe cross-section of a wellbore at different perforation clusters alongthe wellbore. For example, 4505 demonstrates proppant concentrationacross the cross-section of the wellbore at 1 ft before differentclusters where cluster 15 is the heel cluster, which is closest to theinitial injection where the proppant is likely to be uniformlydistributed in frac fluid across the cross-section as illustrated in4515. With fluid and proppant exiting through at least one perforationopening of each subsequent perforation cluster in flow direction fromheel to toe (for example, from cluster 15 to 14 to 13 and thereof), theflow rate or velocity inside the wellbore decreases and proppantsettling increases due to gravity effects. As illustrated in 4505, theproppant concentration is increasing towards the bottom of the wellborewith clusters closer to the toe side (smaller cluster number, forexample from 12 to 8 to 4 to 1) as illustrated in 4520, whichillustrates increased proppant concentration towards the bottom.

The change in proppant concentration across the cross-section of thewellbore for different clusters as it moves from heel to toe is expectedwith higher concentration towards the bottom. For example, graph 4510illustrates the proppant concentration on the X-axis and distance fromcenter of the cross-section of wellbore (Z-ft) on the Y-axis, anddemonstrates that proppant concentration is uniform and close to 1 ppgfrom top to bottom at 1 ft before cluster 15, which will be the firstcluster from flow direction and at the heel of stage. On the other hand,there is continuous increase in bottom concentration, and theconcentration at the bottom can increase (e.g., up to 2.5 ppg) at thebottom at 1 ft before the cluster number 1, which is the last clusterand at the toe of the fracture stage with the lowest velocity inside thewellbore. The increasing proppant concentration at the toe cluster(cluster 1) of the frac stage as illustrated by 4520, which has moreplugging of the wellbore to fracture connectivity as compared to uniformproppant concentration distribution at the heel cluster (cluster 15) asillustrated by 4515.

FIG. 46 illustrates proppant concentration entering the openingperforation at the wellbore at different perforation location alongcircumference and at different perforation clusters because of proppantsettling and segregation with gravity and dependent on frac designparameters, such as fracture fluid viscosity, pump rate, proppant size,perforation opening dimension, etc. For example, 4530 illustrates auniform proppant concentration distribution across the cross-section ofthe wellbore resulting in lower proppant concentration exiting thewellbore and entering the fracture through the wellbore to fractureconnectivity region. With lower concentration and uniform distributionexiting all perforation opening irrespective of their location, there isa lower chance of plugging (partial or complete plugging). On the otherhand, 4535 illustrates increasing proppant concentration towards thebottom of the cross-section of the wellbore resulting in higher proppantconcentration exiting the wellbore and entering the fracture through theperforation opening located at the bottom and lower proppantconcentration exiting the wellbore and entering the fracture through theperforation opening located at top. The higher proppant concentrationexiting the wellbore through the bottom perforation opening has moreplugging (partial or complete) of the wellbore to fracture connectivityregion thereby resulting in non-uniform distribution of fluid andproppant through each perforation opening and perforation clusters, aswell as potential risks of complete plugging of opening perforationrestricting fluid and proppant entry to the fracture.

Provided herein are various embodiments of a wellbore to fractureconnectivity apparatus that may be utilized to represent a wellbore(e.g., perforation of a wellbore) to fracture connection region, forexample, to determine the impact of these various factors on plugging(e.g., partial plugging or complete plugging). As an example, laboratorytesting of proppant transport in a horizontal wellbore setup, withinclusion of the wellbore to fracture connectivity apparatusrepresenting the perforation to fracture connected region, may beutilized to evaluate the impact of various downhole design variables onplugging (e.g., partial plugging and/or complete plugging) of theperforation to fracture connected region of the horizontal wellbore. Thedesign variables for the multistage horizontal wellbore fracture mayinclude different cluster design (e.g., cluster spacing), perforationdesign (e.g., location, count, and diameter), flow parameters (e.g.,injection rate and fluid distribution across each perforation), fracturefluid properties (e.g., viscosity) and proppant properties (e.g.,diameter, specific gravity, and concentration), or any combinationthereof.

Advantageously, the wellbore to fracture connectivity apparatus may beutilized to avoid plugging of the wellbore to fracture connected region.For example, the wellbore to fracture connectivity apparatus may beutilized to select parameters to avoid partial plugging or avoidcomplete plugging of the perforation to fracture connected region fordifferent design variables, which may be referred to as optimizing theparameters. The apparatus may be utilized to select the followingparameters to avoid partial plugging or avoid complete plugging: (a)perforation azimuth (e.g., location across circumference), (b) number ofcluster per stage, (c) cluster design (e.g., cluster spacing), (d)perforation design (e.g., location, count, and diameter), (e) flowparameters (e.g., injection rate in the wellbore and fluid distributionacross each perforation), (f) fracture fluid properties (e.g.,viscosity), (g) proppant properties (e.g., diameter, specific gravity,and concentration), or any combination thereof. The improved or optimumdesigns and correlations developed may be used in the design ofperforation and frac completions for formations involving hydraulicfracturing, such as unconventional formations, to avoid partial pluggingor avoid complete plugging.

Advantageously, the wellbore to fracture connectivity apparatus may beutilized to avoid plugging of the wellbore to fracture connected regionfor a perforation of the wellbore as well as other types of openings ofthe wellbore. Although perforations are discussed throughout thisdisclosure, the wellbore to fracture connectivity apparatus may beutilized when the opening of the wellbore is an opening in a liner or anopening in a sleeve in a similar manner.

The wellbore to fracture connectivity apparatus includes an openingportion, a coupling portion, and a fracture portion with the couplingportion coupling both the opening portion and the fracture portion. Insome embodiments, the wellbore to fracture connectivity apparatusincludes a plurality of one or more of the portions. Some embodimentsmay include a plurality of coupling portions (e.g., two couplingportions). Some embodiments may include a plurality of opening portions(e.g., two opening portions) and a plurality of coupling portions (e.g.,two coupling portions). The apparatus may be created using threedimensional (3D) printing in some embodiments. The portions may beintegral with each other and/or coupled to each other (e.g., screwingtogether or using connectors) depending on the embodiment. For example,a particular apparatus may be manufactured with the portions beingintegral by using 3D printing. Alternatively, 3D printing may beutilized to print separate portions, and then the separate portions maybe coupled together. The portions of the apparatus may be made frompractically any material or combination of materials that can withstandthe fluid (e.g., fracture fluid, slick water, etc.), the proppant (e.g.,sand, manufactured proppant, etc.), or any combination thereof that willflow through the portions. For example, the portions of the apparatusmay be made from the following materials: plastic, metal, thermoplastic,PLA (polylactic acid), fiber, polycarbonate, polypropylene, or anycombination thereof.

In operation, the wellbore to fracture connectivity apparatus may becoupled to an opening of a wellbore portion that represents the wellboreto create a representative near wellbore environment in a laboratorysetting. In operation, a plurality of the wellbore to fractureconnectivity apparatus may even be coupled to a plurality of openings ofthe wellbore portion to create the representative near wellboreenvironment in the laboratory setting. For example, after one or more ofthe apparatus is coupled to the wellbore portion, proppant slurry canflow through the wellbore portion and out the one or more apparatuses tosimulate proppant slurry entering from the perforation to generate atleast one fracture.

For example, the 3D printed cell or other manmade hardware, whichrepresents the wellbore perforation to fracture connectivity profile,can be used in laboratory testing or attached to the wellbore lab modeldirectly or indirectly to study the impact of perforation and fracdesign to fracture interaction on proppant transport in wellbore anddistribution. The study may involve optimization of perforation designparameter along with frac design parameters and various near wellborefracture connectivity properties.

The 3D printed cell or other manmade hardware representing wellboreperforation to fracture connectivity profile can have differentstrength, dimension and roughness, etc. to better represent the fieldconditions. Attaching this equipment directly or indirectly to thewellbore model (referred to as wellbore portion herein) may allow studyof the impact of near wellbore interaction of perforation and fracture,and optimize perforation and frac parameters to not only avoid screenout or sand out, but also to determine improved (or perhaps) optimumperforation azimuth location, etc. Thus, a wellbore perforation tofracture connectivity profile may be determined to test and optimizeperforation and frac design with considerations of fluid and proppanttransport mechanisms and interactions near wellbore.

OPENING PORTION: The opening portion of the wellbore to fractureconnectivity apparatus represents the opening of the wellbore forreceiving the fluid, the proppant, or any combination thereof togenerate the at least one fracture in the formation. The opening of thewellbore may be a perforation of the wellbore an opening in a sleeve ofthe wellbore, an opening in a liner of the wellbore, or other opening ofthe wellbore for receiving the fluid, the proppant, or any combinationthereof to generate the at least one fracture in the formation.

For simplicity, the discussion will focus on the perforation, but thewellbore to fracture connectivity apparatus may be utilized in a similarmanner for other types of openings. The perforation may be created witha perforation gun, for example, through the casing of the wellbore,through the cement of the wellbore, and through the formation near thewellbore. The opening portion may represent the perforation within thecasing, the perforation within the cement, or both. As such, the openingportion may include a casing portion to represent the perforation withinthe casing, a cement portion to represent the perforation within thecement, or both. The perforation within the formation will be discussedin the context of the coupling portion of the wellbore to fractureconnectivity apparatus.

The opening portion may have a variety of shapes such as a sphericalshape (e.g., a cylindrical shape, a conical shape, etc.) or anonspherical shape. In some embodiment, the shape of the opening portionmay be substantially the same shape from the inlet of the openingportion to the outlet of the opening portion. For example, the openingportion may have a circular shape from the inlet of the opening portionthrough the outlet of the opening portion to form a cylinder. In someembodiments, a particular perforation may have atypical shape due toerosion such as a nonspherical shape, and therefore, the shape of theopening portion may be substantially the same as the atypical shape ofthe particular perforation for analysis.

However, in some embodiment, the shape of the opening portion may changefrom the inlet to the outlet of the opening portion depending on theanalysis to be conducted. For example, the opening portion may startwith a circular shape at the inlet of the opening portion to correspondwith a circular perforation in the casing and the cement of thewellbore, and the shape of the opening portion tapers inwards towardsthe outlet of the opening portion.

The inner width or inner diameter of the opening portion may vary. Asthe apparatus may be coupled directly or indirectly with theperforation, the inner width or the inner diameter of the inlet of theopening portion may be substantially the same as the inner width orinner diameter of the perforation in the casing, in the cement, or both.In some embodiments, the inner width or inner diameter of the openingportion may be substantially the same from the inlet of the openingportion to the outlet of the opening portion.

However, in some embodiment, the inner width or inner diameter of theopening portion may change from the inlet of the opening portion to theoutlet of the opening portion. For example, the inner width or innerdiameter of the casing portion of the opening portion may be differentthan the inner width or inner diameter of the cement portion of theopening portion. For example, the inner width or inner diameter of aparticular perforation may become larger or distorted due to erosion,and therefore, the inner width or the inner diameter of the openingportion may be substantially the same as the larger or distorted innerwidth or inner diameter of the particular perforation for analysis.

Of note, the terms “inner width” and “inner diameter” are both utilizedbecause the shape of the opening portion may vary. The term “innerdiameter” is appropriate when the shape of the opening portion has aninner diameter while the term “inner width” is appropriate when theshape of the opening portion has an inner width instead of an innerdiameter.

In some embodiments, the opening portion has an inner width or innerdiameter of at least 0.20 inch from the inlet to the outlet of theopening portion (e.g., at least 0.25 inch, at least 0.3 inch, at least0.35 inch, at least 0.4 inch, at least 0.45 inch, at least 0.5 inch, atleast 0.55 inch, at least 0.6 inch, at least 0.65 inch, at least 0.7inch, at least 0.75 inch, at least 0.8 inch, at least 0.85 inch, atleast 0.9 inch, at least 0.95 inch, at least 1 inch, at least 1.25inches, at least 1.5 inches, or at least 1.75 inches). In someembodiments, the opening portion has an inner width or inner diameter of2.0 inches or less from the inlet to the outlet of the opening portion(e.g., 1.75 inches or less, 1.5 inches or less, 1.25 inches or less, 1inch or less, 0.95 inch or less, 0.9 inch or less, 0.85 inch or less,0.8 inch or less, 0.75 inch or less, 0.7 inch or less, 0.65 inch orless, 0.6 inch or less, 0.55 inch or less, 0.5 inch or less, 0.45 inchor less, 0.4 inch or less, 0.35 inch or less, 0.3 inch or less, or 0.25inch or less). The inner width or inner diameter of the opening portionfrom the inlet to the outlet can range from any of the minimum valuesdescribed above to any of the maximum values described above. Forexample, in some embodiments, the inner width or inner diameter of theopening portion from the inlet to the outlet of the opening portion canbe of from 0.2 inch to 2 inches (e.g., of from 0.3 inch to 0.4 inch, offrom 0.3 inch to 0.5 inch, of from 0.3 inch to 0.8 inch, of from 0.2inch to 1 inch, or of from 0.2 inch to 1.5 inch). In one embodiment, theopening portion has an inner width or inner diameter of about 0.5 inchfrom the inlet to the outlet of the opening portion.

The height of the opening portion may also vary. As the apparatus may becoupled directly or indirectly with the perforation, the height of theopening portion from the inlet of the opening portion to the outlet ofthe opening portion may be substantially the same as the height orthickness of the perforation within the casing, the perforation withinthe cement, or both. In some embodiments, the opening portion has aheight of at least 0.25 inch from the inlet to the outlet of the openingportion (e.g., at least 0.3 inch, at least 0.35 inch, at least 0.4 inch,at least 0.45 inch, at least 0.5 inch, at least 0.55 inch, at least 0.6inch, at least 0.65 inch, at least 0.7 inch, at least 0.75 inch, atleast 0.8 inch, at least 0.85 inch, at least 0.9 inch, at least 0.95inch, at least 1 inch, at least 1.25 inches, or at least 2 inches). Insome embodiments, the opening portion has a height of 2.5 inches or lessfrom the inlet to the outlet of the opening portion (e.g., 2 inches orless, 1.5 inches or less, 1.225 inch or less, 1 inch or less, 0.95 inchor less, 0.9 inch or less, 0.85 inch or less, 0.8 inch or less, 0.75inch or less, 0.7 inch or less, 0.65 inch or less, 0.6 inch or less,0.55 inch or less, 0.5 inch or less, 0.45 inch or less, 0.4 inch orless, 0.35 inch or less, or 0.3 inch or less). The height of the openingportion can range from any of the minimum values described above to anyof the maximum values described above. For example, in some embodiments,the height of the opening portion from the inlet to the outlet of theopening portion can be of from 0.25 inch to 2.5 inches (e.g., of from0.3 inch to 1 inch, of from 0.3 inch to 0.5 inch, or of from 0.3 inch to1 inch). In one embodiment, the opening portion has a height of about1.237 inches.

The opening portion includes at least one passageway within the openingportion to allow the fluid, the proppant, or any combination thereof toflow through the opening portion to the coupling portion. The openingportion includes an inner surface and an outer surface, and the size ofthe at least one passageway may depend on the inner surface of theopening portion. In one embodiment, at least a portion of the innersurface of the opening portion may be smooth. The smooth surface may beutilized to analyze injection of the fluid, the proppant, or anycombination thereof through a new perforation of a casing and cement. Inone embodiment, at least a portion of the inner surface of the openingportion may include an obstruction to represent erosion, inefficientperforation, poor performance of perforation gun charge, etc. Theobstruction may include roughness on the inner surface, uniformity onthe inner surface, layering on the inner surface, etc. As the fluid, theproppant, or any combination thereof will be passing through thepassageway of the opening portion, the outer surface of the openingportion may be smooth.

The area of the passageway of the opening portion may vary. In someembodiments, the opening portion has an area of at least 0.01 inch2(e.g., at least 0.03 inch2, at least 0.10 inch2, at least 0.20 inch2, orat least 1 inch2). In some embodiments, the passageway has an area of 5inches2 or less (e.g., 4 inches2 or less, 3 inches2 or less, 1 inches2or less, or 0.1 inch or less). The area of the passageway can range fromany of the minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the area of thepassageway can be of from 0.01 inch2 to 5 inches2 (e.g., of from 0.01inch2 to 1 inche2 or 0.01 inch2 to 3 inches2). In one embodiment, thepassageway of the opening portion has an area of about 0.19635 inch2. Ofnote, these ranges and values may be used for the passageway of thecoupling portion and the passageway of the fracture portion, but thereasoning and causes resulting in obstructions in the passageway will bedifferent. Thus, the inner surface of for all three opening portion,coupling portion, and fracture portion may have options for differentobstructions that affect the area of the respective passageway fordifferent reasons, causes, etc.

FIG. 47A illustrates one embodiment of the wellbore to fractureconnectivity apparatus 4730 to represent a near wellbore environment4790. The apparatus 4730 has an opening portion 4735 with an inlet 4740and an outlet 4745. The opening portion 4735 has a circular shape fromthe inlet 4740 of the opening portion 4735 through the outlet 4745 ofthe opening portion 4735 to form a cylindrical shape. The openingportion 4735 includes a casing portion 4738 that represents casing 4791of setup 4790 and a cement portion 4739 that represents cement 4792 ofthe near wellbore environment 4790. The gray color of the casing portion4738 and the casing 4791 of the near wellbore environment 4790illustrates that casing portion 4738 represents the casing 4791,including representing the height or thickness of the casing 4791.Similarly, the diagonal line pattern of the cement portion 4739 and thecement 4792 of the near wellbore environment 4790 illustrates that thecement portion 4739 represents the cement 4792, including representingthe height or thickness of the cement 4792.

The near wellbore environment 4790 includes a pipe 4793 utilized in thehorizontal section of a horizontal wellbore with at least one opening,such as perforation 4794. The near wellbore environment 4790 includes adiameter of about 4.276 inches for the pipe only as illustrated by line4795, a diameter of about 5 inches for the pipe and casing only asillustrated by line 4796, and a diameter of about 6.75 inches for thepipe, casing, and cement as illustrated by line 4797. The inner diameterof the inlet 4740 of the opening portion 4735 is substantially the sameas the inner diameter of the perforation 4794 of the pipe 4793 of thenear wellbore environment 4790. As such, in FIG. 47A, the openingportion 4735 has a height of about 1.237 inches from the inlet 4740 tothe outlet 4745 with the casing portion 4738 having a height of about0.362 inch and the cement portion 4739 having a height of about 0.875inch. In FIG. 47A, the opening portion 4735 has an inner diameter ofabout 0.5 inch from the inlet 4740 to the outlet 4745.

The opening portion 4735 includes an inner surface 4736 and an outersurface 4737. For simplicity, in FIG. 47A, the inner surface 4736 andthe outer surface 4737 are essentially smooth from the inlet 4740 of theopening portion 4735 to the outlet 4745 of the opening portion 4750, anda passageway 4731 allows the fluid, the proppant, or any combinationthereof to flow through the opening portion 4735 to a coupling portion4750 of the apparatus 4730. In FIG. 47A, the passageway 4731 of theopening portion 4735 has an area of about 0.19635 square inch. However,the inner surface 4736 may substantially replicate the perforation 4794in the casing 4791 and in the cement 4792 of the near wellboreenvironment 4790. For example, the inner surface 4736 may include anobstruction, such as roughness, unconformity, or layering, evenreplicating erosion, depending on the desired analysis. The innersurface 4736 may include an obstruction from the inlet 4740 of theopening portion 4735 to the outlet 4745 of the opening portion 4750.Those of ordinary skill in the art may appreciate that the openingportion 4735 may be utilized to analyze many sorts of scenarios such asthose of the near wellbore environment 4790, what if scenarios, etc.

FIG. 47B illustrates various non-limiting embodiments of the openingportion 4735 from a side view perspective. The shape of the openingportion 4735 a may be essentially the same from the inlet 4740 a of theopening portion 4735 a to the outlet 4745 a of the opening portion 4735a. The shape of the opening portion 4735 b tapers inward from the inlet4740 b towards the outlet 4745 b. The opening portion 4735 c illustratesthat the shape of the opening portion 4735 c tapers outward the inlet4740 c towards the outlet 4745 c. The opening portion 4735 d hasessentially an hour glass from the inlet 4740 d towards the outlet 4745d.

FIG. 47C illustrates various non-limiting embodiments of the openingportion 4735 from a top view perspective. The inlet 4740 a has acircular shape, an inner surface 4736 a that is smooth, and a passageway4731 a. The inlet 4740 b has a circular shape, an inner surface 4736 athat includes an obstruction 4732 b (e.g., roughness, unconformity, orlayering), and a passageway 4731 b that is smaller than the passageway4731 a due to the obstruction 4732 b. The inlet 4740 c has a circularshape, an inner surface 4736 c that includes an obstruction 4732 c, anda passageway 4731 c that is smaller than the passageway 4731 a due tothe obstruction 4732 c. The inlet 4740 d has a circular shape, an innersurface 4736 d that includes an obstruction 4732 d, and a passageway4731 d that is smaller than the passageway 4731 a due to the obstruction4732 d. The inlet 4740 e has a circular shape, an inner surface 4736 ethat includes an obstruction 4732 e, and a passageway 4731 e that issmaller than the passageway 4731 a due to the obstruction 4732 e. Theobstruction may be present from the inlet to the outlet of the openingportion in some embodiments.

COUPLING PORTION: The coupling portion of the wellbore to fractureconnectivity apparatus represents the wellbore to fracture connectivitybetween the opening portion and a fracture portion. In other words, thecoupling portion represents the perforation within the formation. Forsimplicity, the discussion will mention the perforation, but thewellbore to fracture connectivity apparatus may be utilized in a similarmanner for other types of openings such as an opening in a sleeve, anopening in a liner, or other opening for generating the at least onefracture. The fracture portion will be discussed separately hereinbelow.

The coupling portion may have a variety of shapes such as a sphericalshape (e.g., a triangular shape, a conical shape, etc.) or anonspherical shape. In some embodiment, the dimensions of the inlet ofthe coupling portion may be similar to the dimensions of the outlet ofthe opening portion so that the fluid, the proppant, or any combinationthereof may flow from through the opening portion to the fractureportion. In some embodiment, the narrowest length of the couplingportion may be near the outlet of the opening portion (e.g., appearingas a triangular shape). However, in some embodiments, the narrowestlength of the coupling portion may be near the inlet of the fractureportion (e.g., appearing as an upside triangular shape).

The inner width or inner diameter of the coupling portion may vary. Asthe apparatus may be coupled directly or indirectly with theperforation, the inner width or the inner diameter of the inlet of thecoupling portion may be substantially the same as the inner width orinner diameter of the perforation within the formation. In someembodiments, the inner width or inner diameter of the coupling portionmay be substantially the same from the inlet of the coupling portion tothe outlet of the coupling portion. However, in some embodiment, theinner width or inner diameter of the coupling portion may change (e.g.,increase or decrease) from the inlet of the coupling portion to theoutlet of the coupling portion, for example, depending on the desiredanalysis.

In some embodiments, the coupling portion has an inner width or innerdiameter of at least 0.02 inch from the inlet to the outlet of thecoupling portion (e.g., at least 0.05 inch, at least 0.1 inch, at least0.12 inch, at least 0.15 inch, at least 0.20 inch, at least 0.25 inch,or at least 0.3 inch). In some embodiments, the coupling portion has aninner width or inner diameter of 0.3 inch or less from the inlet to theoutlet of the coupling portion (e.g., 0.25 inch or less, 0.20 inch orless, 0.15 inch or less, 0.10 inch or less, 0.05 inch or less, or 0.03inch or less). The inner width or inner diameter of the coupling portionfrom the inlet to the outlet of the coupling portion can range from anyof the minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the inner width orinner diameter of the coupling portion from the inlet to the outlet ofthe coupling portion can be of from 0.02 inch to 0.3 inch (e.g., of from0.05 inch to 0.15 inch or of from 0.1 inch to 0.2 inch). In oneembodiment, the coupling portion has an inner width or inner diameter ofabout 0.1 inch.

The height of the coupling portion may also vary. As the apparatus maybe coupled directly or indirectly with the perforation, the height ofthe coupling portion from the inlet of the coupling portion to theoutlet of the coupling portion may be substantially the same as theheight of the perforation within the formation. In some embodiments, thecoupling portion has a height of at least 0.02 inch from the inlet tothe outlet of the coupling portion (e.g., at least 0.03 inch, at least0.04 inch, at least 0.05 inch, at least 0.06 inch, at least 0.07 inch,at least 0.08 inch, at least 0.09 inch, at least 0.1 inch, at least 0.5inch, at least 1 inch, at least 1.5 inches, at least 2 inches, at least2.5 inches, at least 3 inches, at least 3.5 inches, at least 4 inches,or at least 4.5 inches). In some embodiments, the coupling portion has aheight of 5 inches or less from the inlet to the outlet of the couplingportion (e.g., 4.5 inches or less, 4 inches or less, 3.5 inches or less,3 inches or less, 2.5 inches or less, 2 inches or less, 1.5 inches orless, 1 inch or less, 0.5 inch or less, 0.1 inch or less, 0.09 inch orless, 0.08 inch or less, 0.07 inch or less, 0.06 inch or less, 0.05 inchor less, 0.04 inch or less, or 0.03 inch or less). The height of thecoupling portion can range from any of the minimum values describedabove to any of the maximum values described above. For example, in someembodiments, the height of the coupling portion from the inlet to theoutlet of the coupling portion can be of from 0.02 inch to 5 inches(e.g., of from 0.02 inch to 1 inch, of from 0.02 inch to 2 inches, or offrom 0.02 inch to 3 inches). In one embodiment, the coupling portion hasa height of about 1 inch.

The length of the coupling portion may also vary. As the apparatus maybe coupled directly or indirectly with the perforation, the length ofthe coupling portion from one side of the coupling portion across to theother side of the coupling portion may be substantially the same as thelength of the perforation within the formation. In some embodiments, thecoupling portion has a length of at least 0.20 inch from one side of thecoupling portion across to the other side of the coupling portion (e.g.,at least 0.30 inch, at least 0.40 inch, at least 0.50 inch, at least0.60 inch, at least 0.70 inch, at least 0.80 inch, at least 0.90 inch,at least 1 inch, at least 2 inches, at least 2.5 inches, at least 3inches, at least 3.5 inches, at least 4 inches, or at least 4.5 inches).In some embodiments, the coupling portion has a length of 5 inches orless from one side of the coupling portion across to the other side ofthe coupling portion (e.g., 4.5 inches or less, 4 inches or less, 3.5inches or less, 3 inches or less, 2.5 inches or less, 2 inches or less,1.5 inches or less, 1 inch or less, 0.5 inch or less, 0.4 inch or less,0.3 inch or less, or 0.25 inch or less). The length of the couplingportion can range from any of the minimum values described above to anyof the maximum values described above. For example, in some embodiments,the length of the coupling portion from one side of the coupling portionacross to the other side of the coupling portion can be of from 0.20inch to 5 inches (e.g., of from 0.1.5 inch to 2 inch, of from 0.1 inchto 3 inches, or of from 1.75 inch to 2 inches). In one embodiment, thecoupling portion has a length of about 1.96 inches.

The coupling portion includes at least one passageway within thecoupling portion to allow the fluid, the proppant, or any combinationthereof to flow through the coupling portion to the fracture portion.The coupling portion includes an inner surface and an outer surface, andthe size of the at least one passageway may depend on the inner surfaceof the coupling portion. In one embodiment, at least a portion of theinner surface of the coupling portion may be smooth. In one embodiment,at least a portion of the inner surface of the coupling portion mayinclude an obstruction to represent the formation, crushed zone, etc.The obstruction may include roughness on the inner surface, unconformityon the inner surface, layering on the inner surface, etc. As the fluid,the proppant, or any combination thereof will be passing through thepassageway of the coupling portion, the outer surface of the couplingportion may be smooth.

The area of the passageway of the coupling portion may vary. In someembodiments, the coupling portion has an area of at least 0.01 inch2(e.g., at least 0.03 inch2, at least 0.10 inch2, at least 0.20 inch2, orat least 1 inch2). In some embodiments, the passageway has an area of 5inches2 or less (e.g., 4 inches2 or less, 3 inches2 or less, 1 inches2or less, or 0.1 inch or less). The area of the passageway can range fromany of the minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the area of thepassageway can be of from 0.01 inch2 to 5 inches2 (e.g., of from 0.01inch2 to 1 inche2 or 0.01 inch2 to 3 inches2). In one embodiment, thepassageway of the coupling portion has an area of about 0.19635 inch2.

Returning to FIG. 47A, this figure illustrates one embodiment of thewellbore to fracture connectivity apparatus 4730 to represent the nearwellbore environment 4790. The apparatus 4730 has a coupling portion4750 with an inlet 4755 and an outlet 4760. The coupling portion 4750has a triangular shape from the inlet 4755 of the coupling portion 4750through the outlet 4760 of the coupling portion 4750. The square patternof the coupling portion 4750 and formation 4799 of the near wellboreenvironment 4790 illustrates that the coupling portion 4750 representsthe perforation 4794 within the formation. In FIG. 47A, the inner width,the height, and the length the coupling portion 4750 may be valuesprovided hereinabove.

The coupling portion 4750 includes an inner surface 4756 and an outersurface 4757. For simplicity, in FIG. 47A, the inner surface 4756 andthe outer surface 4757 are essentially smooth from the inlet 4755 of thecoupling portion 4750 to the outlet 4760 of the coupling portion 4750,and a passageway 4751 allows the fluid, the proppant, or any combinationthereof to flow through the coupling portion 4750 to a fracture portion4760 of the apparatus 4730. However, the inner surface 4756 maysubstantially replicate the perforation 4794 in the formation 4799 ofthe near wellbore environment 4790. For example, the inner surface 4756may include an obstruction, such as roughness, unconformity, orlayering, even replicating the crushed zone, depending on the desiredanalysis. The inner surface 4756 may include an obstruction from theinlet 4755 of the coupling portion 4750 to the outlet 4760 of thecoupling portion 4750. If the coupling portion 4750 includes anobstruction, the obstruction may be similar or different from anobstruction in the opening portion 4735 depending on the desiredanalysis. Those of ordinary skill in the art may appreciate thatcoupling portion 4750 may be utilized to analyze many sorts of scenariossuch as those of the near wellbore environment 4790, what if scenarios,etc.

FIGS. 47D, 47E, and 47F illustrate various non-limiting embodiments ofthe coupling portion 4750 from a front view perspective. In FIG. 47D,the shape of the coupling portion 4750 a is essentially an invertedtriangle from the inlet 4755 a of the coupling portion 4750 a to theoutlet 4760 a of the coupling portion 4750 a. In FIG. 47E, the shape ofthe coupling portion 4750 b is essentially an hourglass from the inlet4755 b of the coupling portion 4750 b to the outlet 4760 b of thecoupling portion 4750 b. In FIG. 47F, the shape of the coupling portion4750 c is essentially triangular from the inlet 4740 c of the couplingportion 4750 c towards the outlet 4745 c of the coupling portion 4750 c,but a different triangular shape than illustrated in FIG. 47A.

FRACTURE PORTION—The fracture portion of the wellbore to fractureconnectivity apparatus represents at least one fracture generated in theformation. For simplicity, the discussion will mention on theperforation, but the wellbore to fracture connectivity apparatus may beutilized in a similar manner for other types of openings such as anopening in a sleeve, an opening in a liner, or other opening forgenerating the at least one fracture. The fracture portion will bediscussed separately hereinbelow.

The fracture portion may have a variety of shapes such as a sphericalshape (e.g., a quadrilateral shape, a rectangular shape, a cube shape,etc.) or a nonspherical shape. In some embodiment, the dimensions of theinlet of the fracture portion may be similar to the dimensions of theoutlet of the coupling portion so that the fluid, the proppant, or anycombination thereof may flow from through the coupling portion to thefracture portion. In some embodiment, the length of the fracture portionmay be substantially the same from the inlet to the outlet of thefracture portion (e.g., appearing as a rectangular shape). In someembodiments, it may be desirable that the length and width of thefracture portion are able to generate substantially the same flow areaas the inner diameter of the perforation.

The inner width or inner diameter of the fracture portion may vary. Asthe apparatus may be coupled directly or indirectly with theperforation, the inner width or the inner diameter of the inlet of thefracture portion may be substantially the same as the inner width orinner diameter of the at least one fracture within the formation. Insome embodiments, the inner width or inner diameter of the fractureportion may be substantially the same from the inlet of the fractureportion to the outlet of the fracture portion. However, in someembodiment, the inner width or inner diameter of the fracture portionmay change (e.g., increase or decrease) from the inlet of the fractureportion to the outlet of the fracture portion, for example, depending onthe desired analysis.

In some embodiments, the fracture portion has an inner width or innerdiameter of at least 0.02 inch from the inlet to the outlet of thefracture portion (e.g., at least 0.05 inch, at least 0.1 inch, at least0.12 inch, at least 0.15 inch, at least 0.20 inch, at least 0.25 inch,or at least 0.3 inch). In some embodiments, the fracture portion has aninner width or inner diameter of 0.3 inch or less from the inlet to theoutlet of the fracture portion (e.g., 0.25 inch or less, 0.20 inch orless, 0.15 inch or less, 0.10 inch or less, 0.05 inch or less, or 0.03inch or less). The inner width or inner diameter of the fracture portionfrom the inlet to the outlet of the fracture portion can range from anyof the minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the inner width orinner diameter of the fracture portion from the inlet to the outlet ofthe fracture portion can be of from 0.02 inch to 0.3 inch (e.g., of from0.05 inch to 0.15 inch or of from 0.1 inch to 0.2 inch). In oneembodiment, the fracture portion has an inner width or inner diameter ofabout 0.1 inch.

The height of the fracture portion may also vary. As the apparatus maybe coupled directly or indirectly with the perforation, the height ofthe fracture portion from the inlet of the fracture portion to theoutlet of the fracture portion may be substantially the same as theheight of the perforation and near wellbore fracture complex fractureregion within the formation. In some embodiments, the fracture portionhas a height of at least 0. 2 inch from the inlet to the outlet of thefracture portion (e.g., at least 0. 3 inch, at least 0.4 inch, at least0.5 inch, at least 0.6 inch, at least 0.7 inch, at least 0.8 inch, atleast 0.9 inch, at least 1 inch, at least 1.5 inch, at least 2 inch, atleast 2.5 inches, at least 3 inches, at least 3.5 inches, at least 4inches, or at least 4.5 inches). In some embodiments, the fractureportion has a height of 5 inches or less from the inlet to the outlet ofthe fracture portion (e.g., 4.5 inches or less, 4 inches or less, 3.5inches or less, 3 inches or less, 2.5 inches or less, 2 inches or less,1.5 inches or less, 1 inch or less, 0.9 inch or less, 0.8 inch or less,0.7 inch or less, 0.6 inch or less, 0.5 inch or less, 0.4 inch or less,or 0.3 inch or less). The height of the fracture portion can range fromany of the minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the height of thefracture portion from the inlet to the outlet of the fracture portioncan be of from 0. 2 inch to 5 inches (e.g., of from 0.2 inch to 1 inch,of from 0.2 inch to 2 inches, or of from 0.22 inch to 3 inches). In oneembodiment, the fracture portion has a height of about 2 inches.

The length of the fracture portion may also vary. As the apparatus maybe coupled directly or indirectly with the perforation, the length ofthe fracture portion from one side of the fracture portion across to theother side of the fracture portion may be substantially the same as thelength of the perforation within the formation. In some embodiments, thefracture portion has a length of at least 0.2 inch from one side of thefracture portion across to the other side of the fracture portion (e.g.,at least 0.3 inch, at least 0.4 inch, at least 0.5 inch, at least 0.6inch, at least 0.7 inch, at least 0.8 inch, at least 0.9 inch, at least1 inch, at least 1.5 inch, at least 2 inches, at least 2.5 inches, atleast 3 inches, at least 3.5 inches, at least 4 inches, or at least 4.5inches). In some embodiments, the fracture portion has a length of 5inches or less from one side of the fracture portion across to the otherside of the fracture portion (e.g., 4.5 inches or less, 4 inches orless, 3.5 inches or less, 3 inches or less, 2.5 inches or less, 2 inchesor less, 1.5 inches or less, 1 inch or less, 0.9 inch or less, 0.8 inchor less, 0.7 inch or less, 0.6 inch or less, 0.5 inch or less, 0.4 inchor less, or 0.3 inch or less). The length of the fracture portion canrange from any of the minimum values described above to any of themaximum values described above. For example, in some embodiments, thelength of the fracture portion from one side of the fracture portionacross to the other side of the fracture portion can be of from 0.2 inchto 5 inches (e.g., of from 0.2 inch to 1 inch, of from 0.2 inch to 2inches, or of from 0.2 inch to 3 inches). In one embodiment, thefracture portion has a length of about 1.9635 inches.

The fracture portion includes at least one passageway within thefracture portion to allow the fluid, the proppant, or any combinationthereof to flow through the fracture portion and exit the apparatus.Alternatively, the fluid, the proppant, or any combination thereof toflow through the fracture portion to another coupling portion then toanother opening portion and then exit the apparatus. The fluid, theproppant, or any combination thereof that exits the apparatus may becollected in a container, for example, to compare the quantity that wasinjected in the apparatus compared to the quantity that exited theapparatus.

The fracture portion includes an inner surface and an outer surface, andthe size of the at least one passageway may depend on the inner surfaceof the fracture portion. In one embodiment, at least a portion of theinner surface of the fracture portion may be smooth. In one embodiment,at least a portion of the inner surface of the fracture portion mayinclude an obstruction to represent the formation. The obstruction mayinclude roughness on the inner surface, unconformity on the innersurface, unconformity on the inner surface, layering on the innersurface, etc. As the fluid, the proppant, or any combination thereofwill be passing through the passageway of the fracture portion, theouter surface of the fracture portion may be smooth.

The area of the passageway of the fracture portion may vary. In someembodiments, the fracture portion has an area of at least 0.01 inch2(e.g., at least 0.03 inch2, at least 0.10 inch2, at least 0.20 inch2, orat least 1 inch2). In some embodiments, the passageway has an area of 5inches2 or less (e.g., 4 inches2 or less, 3 inches2 or less, 1 inches2or less, or 0.1 inch or less). The area of the passageway can range fromany of the minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the area of thepassageway can be of from 0.01 inch2 to 5 inches2 (e.g., of from 0.01inch2 to 1 inche2 or 0.01 inch2 to 3 inches2). In one embodiment, thepassageway of the fracture portion has an area of about 0.19635 inch2.

Returning to FIG. 47A, this figure illustrates one embodiment of thewellbore to fracture connectivity apparatus 4730 to represent the nearwellbore environment 4790. The apparatus 4730 has a fracture portion4765 with an inlet 4770 and an outlet 4775. The fracture portion 4765has a rectangular shape from the inlet 4770 of the fracture portion 4765through the outlet 4775 of the fracture portion 4765. The dot pattern ofthe fracture portion 4765 and a fracture 4798 in the formation 4799 ofthe near wellbore environment 4790 illustrates that the fracture portion4765 represents the fracture 4798. In FIG. 47A, the inner width, theheight, and the length the fracture portion 4765 may be values providedhereinabove.

The fracture portion 4765 includes an inner surface 4766 and an outersurface 4767. For simplicity, in FIG. 47A, the inner surface 4766 andthe outer surface 4767 are essentially smooth from the inlet 4770 of thefracture portion 4765 to the outlet 4775 of the fracture portion 4765,and a passageway 4761 allows the fluid, the proppant, or any combinationthereof to flow through the fracture portion 4765 to a second couplingportion 4750 and then to a second opening portion 4735 of the apparatus4730. However, the inner surface 4766 may substantially replicate thefracture 4798 in the formation 4799 of the near wellbore environment4790. For example, the inner surface 4766 may include an obstruction,such as roughness, unconformity, or layering depending on the desiredanalysis. The inner surface 4766 may include an obstruction from theinlet 4766 of the fracture portion 4765 to the outlet 4775 of thefracture portion 4765. If the fracture portion 4765 includes anobstruction, the obstruction may be similar or different from anobstruction in the coupling portion 4750 depending on the analysis.Those of ordinary skill in the art may appreciate that fracture portion4765 may be utilized to analyze many sorts of scenarios such as those ofthe near wellbore environment 4790, what if scenarios, etc.

Optionally, as illustrated in FIGS. 47A and 47G the fracture portion4765 may include at least one removable panel, such as a panel 4763, tofacilitate cleaning of the interior of the fracture portion 4765. Atleast one screw, nut and bolt, or other connector 4764 may be utilizedfor removing and securing the panel 4763. Furthermore, the fractureportion 4765 may include at least one transparent panel to facilitateviewing of the interior of the fracture portion 4765. The panel 4763 maybe removable and transparent. FIG. 47H illustrates various non-limitingembodiments of the inner surface of the panel 4763, for example, tosimulate different fracture roughness. The inner surface of the panel4763 a is smooth. The inner surface of the panel 4763 b has roughness.The inner surface of the panel 4763 c has a different type of roughnesscompared to the panel 4763 c. Although illustrated in the context of thepanel 4763, the inner surface of the other panel (not shown) that islocated opposite of the panel 4763 may be similar or different than thepanel 4763. FIGS. 47D and 47E illustrate alternative shapes for thefracture portion illustrated as 4765 a and 4765 b, respectively.

FIG. 47I illustrates various non-limiting embodiments of the inlet 4770of the fracture portion 4765 from a top view perspective. The inlet 4770a has a rectangular shape, an inner surface 4766 a that is smooth, and apassageway 4761 a. The inlet 4770 b has a rectangular shape, an innersurface 4766 b that includes an obstruction 4768 b (e.g., roughness,unconformity, or layering), and a passageway 4761 b that is smaller thanthe passageway 4761 a due to the obstruction 4768 b. The inlet 4770 chas a rectangular shape, an inner surface 4766 c that includes anobstruction 4768 c, and a passageway 4761 c that is smaller than thepassageway 4761 a due to the obstruction 4768 c. The inlet 4740 d has arectangular shape, an inner surface 4766 d that includes an obstruction4768 d, and a passageway 4731 d that is smaller than the passageway 4761a due to the obstruction 4768 d. The inlet 4770 e has a rectangularshape, an inner surface 4766 e that includes an obstruction 4768 e, anda passageway 4761 e that is smaller than the passageway 4761 a due tothe obstruction 4768 e. The outlet 4775 may be the same or differentthan the inlet 4770 depending on the embodiment. The obstruction may bepresent from the inlet to the outlet of the fracture portion in someembodiments.

FIG. 47J illustrates various non-limiting embodiments of the side panel4762 of the fracture portion 4765 from a side view perspective. Thepanel 4762 a has an inner width that is substantially the samethroughout the panel 4762 a, but the panels 4762 f and 4762 g illustratethat the width inner with may change. The panels 4762 a, 4762 f, and4762 g have inner surfaces that are smooth. In the other hand, thepanels 4762 b, 4762 c, 4762 d, and 4762 e have rectangular shapes andtheir inner surfaces include various obstructions shown in black thatreduce the passageways as compared to the passageways of panels 4762 a,4762 f, and 4762 g. One of ordinary skill in the art will appreciatethat the various embodiments of the apparatus highlight the flexibilityof the apparatus, for example, the panels 4762 may have roughness thatmay be the same or different than the roughness of the panels 4763 inFIG. 47H.

FIGS. 47K and 47L illustrate that a plurality of the apparatus 4730 maybe coupled together. FIG. 47K illustrates that two apparatuses 4730 maybe coupled together, for example, screwed together. Alternatively, thetwo apparatuses 4730 may be manufactured as a single integral apparatus,for example, using 3D printing. In some embodiments, one of more of thedimensions may be different between the plurality of coupled apparatuses4730. For example, the fracture portion of the bottom apparatus 4730 maybe smaller than the fracture portion in the top apparatus 4730 torepresent a larger fracture in the top apparatus 4730 and a represent asmaller fracture in the bottom apparatus 4730. FIG. 47K illustrates oneembodiment of coupling a plurality of the apparatus in series.

FIG. 47L illustrates that a plurality of the apparatus 4730 may becoupled via a coupling apparatus, such as a coupling apparatus 4780. Forexample, the coupling apparatus may include tubing, such as tubing 4781,and inlet 4782. The fluid, the proppant, or any combination thereofflows into the inlet 4782, flows into the tubing 4781, and flows intothe two apparatuses. The components illustrated in FIG. 47L may becreated as an integral piece, for example, by 3D printing.Alternatively, the components illustrated in FIG. 47L may be separatepieces that are coupled together, for example, by screwing or otherconnectors. FIG. 47L illustrates one embodiment of coupling a pluralityof the apparatus in parallel.

FIG. 47M illustrates one embodiment of a system comprising at least onewellbore to fracture connectivity, illustrated as a system 4785. Thesystem 4785 includes a wellbore portion 4786 to represent a part of awellbore. For example, the wellbore portion 4786 may be made ofsubstantially the same material as the wellbore. The wellbore portion4786 includes at least one opening 4787, such as a perforation, openingin a sleeve, opening in a liner, etc.), and the apparatus 4730 may becoupled directly or indirectly at each desired opening 4787. Theapparatus 4730 may be coupled indirectly to the opening 4787 of thewellbore portion 4786 using a tubing, such as tubing 4788. The tubing4788 may be similar to the tubing 4781 of FIG. 47N. The tubing 4788 andthe tubing 4781 of FIG. 47N may be practically any tubing utilized fortransporting the fluid, the proppant, or any combination thereof. Thearea of the passageway of the tubing/flow line is substantially the sameas the area of the passageway of the opening portion in someembodiments.

In operation, the fluid, the proppant, or any combination thereof, suchas a proppant slurry, may flow through the wellbore portion 4786 (asillustrated in the arrow in FIG. 47M) and then flows through at leastone opening 4787 and into the coupled apparatus 4730 and out of thecoupled apparatus 4730. For example, the flow rate of the proppantslurry that exits a particular coupled apparatus 4730, as well as thequantity of proppant and quantity of fluid that exit out of theparticular apparatus 4730, may be determined and utilized to analyze thewellbore to fracture connectivity and plugging for those conditions.Flow meters, scales, and other conventional laboratory equipment may beutilized for the analysis.

Turning more specifically to FIG. 47N, this setup represents asubsurface wellbore configuration with single or multiple perforationclusters during a hydraulic fracturing operation. The fluid and proppantslurry is pre-mixed or mixed on-the-fly and is being injected togetherinto the wellbore in the direction shown by the arrows (from heel of thewellbore to toe of the wellbore). The fluid and proppant exit from thewellbore through at least one perforation opening and at least oneperforation cluster representing fluid and proppant entry in fracture,to generate and extend the fracture through at least one perforationopening and at least one perforation cluster.

In each cluster, the perforation opening design can be the same ordifferent, can be placed at the same or different location(circumference), and can have the same or different number or size.

The quantity of fluid and proppant exiting through each wellbore tofracture connectivity apparatus as well as resulted plugging (partial orcomplete plugging) may be measured and quantified, using flowmeasurement apparatus, or differential pressure measurement, or volumeand weight measurement of collected fluid and proppant, or anycombination thereof. FIG. 47N illustrates three clusters of the system4785. Various receptacles 4789 are illustrated for collecting the fluid,the proppant, or any combination thereof that exit the correspondingapparatus.

FIG. 48 illustrates one embodiment of a process, such as a process 4800,for using a wellbore to fracture connectivity apparatus, such as usingthe setup illustrated in FIG. 47N. To study the impact of wellbore tofracture connectivity profile and multistage hydraulic fracture designparameters on plugging severity (partial or complete plugging) withproppant, laboratory testing may be conducted. Of note, if a newwellbore to fracture apparatus is to be made (e.g., via 3D printing),the method 4800 may proceed with 4805 and 4810. If a wellbore tofracture apparatus was previously made, then the method 4800 may proceedwith 4815.

At 4805, the method 4800 includes: Review and define the wellbore tofracture connectivity design parameters for given and expectedsubsurface wellbore condition and completion design parameters such assize of opening perforation, thickness and size of casing, size of openhole and cement thickness, perforation gun charge and expectedperforation penetrated depth, diameter and shape, expected fracturewidth and complexity for selected fracture fluid type and formation rockproperties (geomechanical parameter and heterogeneity, etc.).

At 4810, the method 4800 includes: Manufacture or make the wellbore tofracture connectivity apparatus as per defined design specification at4805.

The wellbore portion, such as 4786 in FIG. 47N, may be made using 4815and 4820. At 4815, the method 4800 includes: Review and definemultistage hydraulic fracture design parameters for given, planned andexpected subsurface wellbore condition and completion design parameterssuch as wellbore opening design (number of opening and location),Perforation location along circumference (azimuth), Number of clustersper stage, Fracture fluid rheology (viscosity), Proppant size (diameter)and specific gravity, Proppant and fluid mix ratio (concentration), Pumprate (velocity), fluid and proppant exit rate through at least oneperforation opening and fluid and at least one perforation cluster. In alaboratory setting, decisions may be made about the wellbore portionsuch as selection of a steel pipe, plastic pipe, a transparent pipe tofacilitate visual confirmation of plugging, etc., as well as decisionsabout scaling down. The type of fluid, the type of proppant,concentration, etc. may also be selected.

At 4820, the method 4800 includes: Prepare suitable and representativephysical laboratory setup of wellbore, completion design (number andlocation of perforation opening and perforation cluster), and connectwellbore to fracture connectivity apparatus directly or indirectly withwellbore opening. The user may create the openings in the transparentpipe with a drill or other tool in manner consistent with 4815, forexample, drill openings in the desired location (azimuth), drill thedesired number of holes, sizes of holes, etc. At least one wellbore tofracture connectivity apparatus may be physically coupled to thewellbore portion, tubing/flow lines may be physically added, a pump maybe physically added for the upcoming injection, a tank may be physicallyadded for providing the fluid and proppant, etc.

At 4825, the method 4800 includes: Inject fracture fluid and proppantslurry (pre-mixed or mixed on-the-fly) as per hydraulic fracture designparameters through the represented wellbore portion with the slurryexiting through the wellbore to fracture connectivity apparatus for testperiod of at least 1 minute and as long as field pumping time (estimated2 hours). For example, the slurry may be injected into the wellboreportion and into each coupled wellbore to fracture connectivityapparatus.

At 4830, the method 4800 includes: Collect and measure the quantity offluid and proppant exiting through each wellbore to fractureconnectivity apparatus as well as resulted plugging (partial or completeplugging) using flow measurement apparatus, differential pressuremeasurement, or volume and weight measurement of collected fluid andproppant, or any combination thereof. For example, the fluid andproppant exiting each coupled wellbore to fracture connectivityapparatus may be collected and measured to generate measurement data.Each coupled apparatus may include a flow meter to measure flow rate.Each coupled apparatus may include a pressure gauge or pressuretransducer at the inlet of the coupled apparatus and another at theoutlet of the apparatus to determine a differential pressure. Volume andweight of the fluid and proppant exiting each coupled apparatus may bedetermined using scales, etc.

At 4835, the method 4800 includes: Quantify plugging (partial orcomplete plugging) for the wellbore to fracture connectivity design andparameters (as defined in 4805) and multistage hydraulic fracture designand parameters (as defined in 4815). Plugging may be quantified for eachcoupled apparatus via a decrease in the flow rate that indicatesplugging, an increase in differential pressure that indicates plugging,lower quantity of proppant as compared to fluid volume indicatesplugging, etc. Thus, plugging may be quantified using the flow rate,ratio, pressure, quantity of exiting fluid and proppant, etc.

For example, if the flow rate was X, then there's a decrease in flowrate in apparatus1, and then there's an additional decrease inapparatus2, etc., then this suggests partial plugging that isquantifiable via the changes in flow rate. There is complete plugging ifthe flow rate is about 0. As another example, if there is a zeropressure differential, and then there's a 1 psi increase in apparatus1,and then there's a 2 psi increase in apparatus 2, etc. then thissuggests at least partial plugging that is quantifiable via the changesin differential pressure. Quantifying plugging may include performingrelative comparisons across different apparatuses, different locations,etc. including even comparisons with base cases without proppant.

All of the steps 4805 to 4835 can be repeated for different wellbore tofracture connectivity design and parameters (as defined in 4805) anddifferent multistage hydraulic fracture design and parameters (asdefined in 4815).

At 4840, the method 4800 includes: Analyze result and impact ofdifferent wellbore to fracture connectivity apparatus design andparameters (as defined in 4805) and different multistage hydraulicfracture design and parameters (as defined in 4815) to determine whichhydraulic fracture design parameter(s) to alter to reduce plugging,which may be referred to as optimizing the hydraulic fracture designparameters. The hydraulic fracture design parameter(s) alteration maythen be implemented in a hydraulic fracture operation. For example,plugging data for a particular wellbore to fracture apparatus may becompared to a base case having the same fluid but no proppant, and basedon this comparison, decisions may be made to change the proppant, changethe location (azimuth) of the opening, change the fluid, etc. to reduceplugging.

As another example, it may be identified that slickwater with 14clusters per stage with a perforation inner diameter of 0.25 inch andproppant of 30-50 mesh size is causing plugging in the openings locatedat the bottom of the wellbore portion. Moreover, it may be identifiedthat the plugging starts occurring after 10 clusters so only the last 4clusters start showing the plugging. The decision may be made to use 10clusters instead of 14 clusters or avoid the perforations at the bottomlocation.

If testing is run again with 100 mesh proppant and plugging is notidentified in those 4 clusters with bottom perforations, then thedecision may be made to switch to the 100 mesh proppant instead of the30-50 mesh.

If testing didn't reveal plugging with the perforation of inner diameter0.35, then the decision may be made to switch to 0.25 inch.

In some embodiments, the system further comprises at least one otherwellbore to fracture connectivity apparatus coupled to at least oneother opening of the wellbore portion; and further comprising varyingdesign parameters of the wellbore to fracture connectivity apparatus,varying design parameters of the at least one other wellbore to fractureconnectivity apparatus, varying hydraulic fracturing design parametersof the wellbore portion, or any combination thereof while repeating thesteps of injecting, collecting, measuring, and quantifying. Theembodiment may further include comparing the plugging data of thewellbore to fracture connectivity apparatus and the at least one otherapparatus to determine impact of different profiles of wellbore tofracture connectivity apparatuses and hydraulic fracture designparameters to determine which hydraulic fracture design parameter toalter to reduce plugging. The embodiment may further include alteringthe hydraulic fracture design parameter in a hydraulic fractureoperation. On the other hand, another embodiment includes varying designparameters of the wellbore to fracture connectivity apparatus, varyinghydraulic fracturing design parameters of the wellbore portion, or anycombination thereof while repeating the steps of injecting, collecting,measuring, and quantifying.

From 4835, the method 4800 may proceed to 4855, then to 4860, and thento 4815. At 4855, the method 4800 includes: Repeat flow test for otherhydraulic fracturing design parameters. At 4860, multistage hydraulicfracturing design parameters: wellbore opening design (number of openingand location), Perforation azimuth, Number of clusters per stage,Fracture fluid rheology (viscosity), Proppant size (diameter) andspecific gravity, Proppant and fluid mix ratio (concentration), Pumprate (velocity), or any combination thereof.

From 4835, the method 4800 may proceed to 4845, then to 4850, and thento 4805. At 4855, the method 4800 includes: Repeat flow test for otherwellbore to fracture connectivity profile. At 4850, Wellbore to fractureconnectivity apparatus parameters: Size of opening in wellbore toreceive fluid and proppant and deliver to fracture (example, perforationdiameter and shape)=Size of opening portion (diameter and shape);Wellbore pipe thickness and cement annular thickness=Length of openingportion; or any combination thereof.

Those of ordinary skill in the art will appreciate that various otherembodiments are possible and the claims are not limited to theembodiments provided herein. Modifications may be made to an embodimentprovided herein. For example, the term couple may include an integralscenario in which the opening portion, the coupling portion, and thefracture portion (and optional a second coupling portion and a secondopening portion) form an integral three dimensional wellbore to fractureconnectivity apparatus (e.g., the entire apparatus with all the portionsis 3D printed as a single piece) as discussed hereinabove.Alternatively, the term couple may include screwing or using connectorsto join physically separate portions together. Furthermore, the term“couple”, “coupled”, and the like may include fluidically coupled as thefluid, the proppant, or any combination thereof flows through theapparatus from portion to portion.

Numerous specific details are set forth in order to provide a thoroughunderstanding of the subject matter presented herein. But it will beapparent to one of ordinary skill in the art that the subject matter maybe practiced without these specific details. In other instances,well-known methods, procedures, components, and circuits have not beendescribed in detail so as not to unnecessarily obscure aspects of theembodiments.

Although some of the various drawings illustrate a number of logicalstages in a particular order, stages that are not order dependent may bereordered and other stages may be combined or broken out. While somereordering or other groupings are specifically mentioned, others will beobvious to those of ordinary skill in the art and so do not present anexhaustive list of alternatives. Moreover, it should be recognized thatthe stages could be implemented in hardware, firmware, software or anycombination thereof.

The foregoing description, for purpose of explanation, has beendescribed with reference to specific embodiments. However, theillustrative discussions above are not intended to be exhaustive or tolimit the invention to the precise forms disclosed. Many modificationsand variations are possible in view of the above teachings. Theembodiments were chosen and described in order to best explain theprinciples of the invention and its practical applications, to therebyenable others skilled in the art to best utilize the invention andvarious embodiments with various modifications as are suited to theparticular use contemplated.

1. A computer-implemented method of determining a hydraulic fracturecompletion configuration for a wellbore that extends through asubterranean formation, the method comprising: calculating a stressprofile across a plurality of perforation clusters within a fracturestage of the wellbore; calculating a fracture pressure parameter foreach perforation cluster of the plurality of perforation clusters withinthe fracture stage of the wellbore as a function of the stress profileacross the plurality of perforation clusters within the fracture stage,a perforation friction that accounts for perforation hole erosion, afracture net pressure, and a fracture closure pressure; and determininga quantity of perforation clusters in the plurality of the perforationclusters within the fracture stage, a quantity of perforation holes foreach perforation cluster of the plurality of perforation clusters withinthe fracture stage, a diameter of the perforation holes for eachperforation cluster of the plurality of perforation clusters within thefracture stage, a spacing between each perforation cluster of theplurality of perforation clusters within the fracture stage, aninjection distribution across the plurality of perforation clusterswithin the fracture stage, or any combination thereof, for the hydraulicfracture completion configuration based on the calculated fracturepressure parameters.
 2. The method of claim 1, wherein determining basedon the calculated fracture pressure parameters comprises iterativelyadjusting the calculated fracture pressure parameters to reduce avariation in a distribution of the calculated fracture pressureparameters for the plurality of the perforation clusters within thefracture stage.
 3. The method of claim 1, wherein determining based onthe calculated fracture pressure parameters comprises iterativelyadjusting the calculated fracture pressure parameters to identify thehydraulic fracture completion configuration with a closest match betweena distribution of the calculated fracture pressure parameters for theplurality of the perforation clusters within the fracture stage to atargeted distribution of calculated fracture pressure parameters for theplurality of the perforation clusters within the fracture stage.
 4. Themethod of claim 1, wherein determining based on the calculated fracturepressure parameters comprises iteratively adjusting the calculatedfracture pressure parameters to reduce a variation in the injectiondistribution across the plurality of perforation clusters within thefracture stage.
 5. The method of claim 1, wherein determining based onthe calculated fracture pressure parameters comprises iterativelyadjusting the calculated fracture pressure parameters to identify thehydraulic fracture completion configuration with a closest match betweenthe injection distribution across the plurality of perforation clusterswithin the fracture stage to a target injection distribution across theplurality of perforation clusters within the fracture stage.
 6. Themethod of claim 1, wherein the fracture pressure parameter for eachperforation cluster of the plurality of perforation clusters within thefracture stage of the wellbore is further calculated as a function offracture height.
 7. The method of claim 1, wherein the stress profilecomprises an initial stress profile or changes thereto induced by ahydraulic fracturing operation, fluid depletion in the subterraneanformation, one or more other wellbore operations, or any combinationthereof.
 8. The method of claim 7, wherein the changes to the initialstress profile induced by the hydraulic fracturing operation compriseshydraulic fracturing within the fracture stage in the wellbore,hydraulic fracturing in an adjacent fracture stage in the wellbore,hydraulic fracturing in a neighboring wellbore, or any combinationthereof.
 9. The method of claim 1, wherein determining the injectiondistribution across the plurality of perforation clusters within thefracture stage further comprises using parameters to represent aquantity of perforation clusters within the fracture stage, a spacingbetween the quantity of perforation clusters within the fracture stage,a diameter of the perforation holes for the quantity of perforationclusters within the fracture stage, the quantity of perforation holesfor the quantity of perforation clusters within the fracture stage, aperforation hole erosion value, a perforation phasing configuration, aninjection pump rate, an injection fluid density, a fracture netpressure, a fracture height, and a fracture closure pressure.
 10. Themethod of claim 1, wherein determining the quantity of perforation holesfor each perforation cluster of the plurality of perforation clusterswithin the fracture stage further comprises using parameters torepresent a quantity of perforation clusters within the fracture stage,a spacing between the quantity of perforation clusters within thefracture stage, a diameter of the perforation holes for the quantity ofperforation clusters within the fracture stage, a perforation holeerosion value, a perforation friction pressure target, a perforationphasing configuration, an injection pump rate, an injection fluiddensity, a fracture net pressure, a fracture height, and a fractureclosure pressure.
 11. The method of claim 1, further comprisingperforming a sensitivity analysis on the hydraulic fracture completionconfiguration using combinations of multiple values of the fracture netpressure, of fracture height, or both.
 12. The method of claim 1,further comprises: determining an injection pump rate across theplurality of perforation clusters within the fracture stage for thehydraulic fracture completion configuration, across at least oneadditional fracture stage for the hydraulic fracture completionconfirmation, or any combination thereof; wherein determining theinjection pump rate further comprises using parameters to represent aminimum injection pump rate, a maximum injection pump rate, a minimumdiameter of the perforation holes for the quantity of perforationclusters within the fracture stage, and a maximum diameter of theperforation holes for the quantity of perforation clusters within thefracture stage.
 13. The method of claim 1, further comprising:calculating a friction loss limit for the fracture stage of thewellbore, a friction loss limit for at least one additional fracturestage for the hydraulic fracture completion configuration, or anycombination thereof; wherein the friction loss limit is calculated basedon a maximum allowable surface pressure, a hydrostatic pressure, thefracture net pressure, the fracture closure pressure, a net wellborepressure, a target perforation friction, or any combination thereof. 14.The method of claim 13, further comprising calculating an injection pumprate for each fracture stage of the wellbore based on the friction losslimit, and optionally updating the hydraulic fracture completionconfiguration based on the injection pump rate for each fracture stageof the wellbore.
 15. The method of claim 1, further comprising:calculating the stress profile across the plurality of perforationclusters for multiple fracture stages of the wellbore; calculating thefracture pressure parameter for each perforation cluster of theplurality of perforation clusters for the multiple fracture stages ofthe wellbore; and determining the quantity of perforation clusters inthe plurality of the perforation clusters for the multiple fracturestages, the quantity of perforation holes for each of the plurality ofperforation clusters for the multiple fracture stages, the diameter ofthe perforation holes for each perforation cluster of the plurality ofperforation clusters for the multiple fracture stages, the spacingbetween each perforation cluster of the plurality of perforationclusters for the multiple fracture stages, the injection distributionacross the plurality of perforation clusters for the multiple fracturestages, or any combination thereof, for the hydraulic fracturecompletion configuration based on the calculated fracture pressureparameter for each perforation cluster of the plurality of perforationclusters for the multiple fracture stages of the wellbore.
 16. Themethod of claim 1, further comprises determining a layout for theperforation holes of each perforation cluster of the plurality ofperforation clusters within the fracture stage for the hydraulicfracture completion configuration or determining a layout for theperforation holes of each perforation cluster of at least one otherfracture stage for the hydraulic fracture completion configuration. 17.The method of claim 16, wherein determining the layout includesdetermining orientation of at least one perforation hole.
 18. The methodof claim 16, wherein determining the layout includes obtaining a moreuniform fluid distribution across perforation clusters, obtaining a moreuniform proppant distribution across perforation clusters, or anycombination thereof
 19. A computer system, comprising: one or moreprocessors; memory; and one or more programs, wherein the one or moreprograms are stored in the memory and configured to be executed by theone or more processors, the one or more programs including instructionsthat when executed by the one or more processors cause execution of amethod of determining a hydraulic fracture completion configuration fora wellbore that extends through a subterranean formation, the methodcomprising: calculating a stress profile across a plurality ofperforation clusters within a fracture stage of the wellbore;calculating a fracture pressure parameter for each perforation clusterof the plurality of perforation clusters within the fracture stage ofthe wellbore as a function of the stress profile across the plurality ofperforation clusters within the fracture stage, a perforation frictionthat accounts for perforation hole erosion, a fracture net pressure, anda fracture closure pressure; and determining a quantity of perforationclusters in the plurality of the perforation clusters within thefracture stage, a quantity of perforation holes for each perforationcluster of the plurality of perforation clusters within the fracturestage, a diameter of the perforation holes for each perforation clusterof the plurality of perforation clusters within the fracture stage, aspacing between each perforation cluster of the plurality of perforationclusters within the fracture stage, an injection distribution across theplurality of perforation clusters within the fracture stage, or anycombination thereof, for the hydraulic fracture completion configurationbased on the calculated fracture pressure parameters.
 20. A method ofperforming a hydraulic fracturing operation on a wellbore that extendsthrough a subterranean formation, the method comprising: performing ahydraulic fracturing operation on the wellbore using a hydraulicfracture completion configuration, wherein the hydraulic fracturecompletion configuration is determined by: calculating a stress profileacross a plurality of perforation clusters within a fracture stage ofthe wellbore; calculating a fracture pressure parameter for eachperforation cluster of the plurality of perforation clusters within thefracture stage of the wellbore as a function of the stress profileacross the plurality of perforation clusters within the fracture stage,a perforation friction that accounts for perforation hole erosion, afracture net pressure, and a fracture closure pressure; and determininga quantity of perforation clusters in the plurality of the perforationclusters within the fracture stage, a quantity of perforation holes foreach perforation cluster of the plurality of perforation clusters withinthe fracture stage, a diameter of the perforation holes for eachperforation cluster of the plurality of perforation clusters within thefracture stage, a spacing between each perforation cluster of theplurality of perforation clusters within the fracture stage, aninjection distribution across the plurality of perforation clusterswithin the fracture stage, or any combination thereof, for the hydraulicfracture completion configuration based on the calculated fracturepressure parameters.
 21. A system of performing a hydraulic fracturingoperation on a wellbore that extends through a subterranean formation,the system comprising: a perforation gun for generating perforations inthe wellbore according to a hydraulic fracture completion configuration,wherein the hydraulic fracture completion configuration is determinedby: calculating a stress profile across a plurality of perforationclusters within a fracture stage of the wellbore; calculating a fracturepressure parameter for each perforation cluster of the plurality ofperforation clusters within the fracture stage of the wellbore as afunction of the stress profile across the plurality of perforationclusters within the fracture stage, a perforation friction that accountsfor perforation hole erosion, a fracture net pressure, and a fractureclosure pressure; and determining a quantity of perforation clusters inthe plurality of the perforation clusters within the fracture stage, aquantity of perforation holes for each perforation cluster of theplurality of perforation clusters within the fracture stage, a diameterof the perforation holes for each perforation cluster of the pluralityof perforation clusters within the fracture stage, a spacing betweeneach perforation cluster of the plurality of perforation clusters withinthe fracture stage, an injection distribution across the plurality ofperforation clusters within the fracture stage, or any combinationthereof, for the hydraulic fracture completion configuration based onthe calculated fracture pressure parameters; and a pump and an injectionline configured to inject fluid through the generated perforations ofthe wellbore into the subterranean formation to perform the hydraulicfracturing operation.